## cr17367

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### Preface — mission, scope, and key dates
- Mission: Technical assistance to Kampala and Entebbe on extractive industry (EI) fiscal regimes requested by the Delegation of the Republic of Uganda at the Annual Meetings 2014; mission period February 25 to March 10 2015.
- Steering and team: IMF’s MNRW TTF Module 1 Project; team led by Philip Daniel, Diego Mesa Puyo (FAD), Emil M. Sunley (FAD External Expert), and Lee Burns (LEG Expert).
- Engagement: MFPED, MEMD, URA, Bank of Uganda, Technical Group on Petroleum, civil society, international oil companies, professional advisors, and donors.
- Key project-level dates and figures:
  - Mission visit: February 25 to March 10 2015.
  - Prior request: Annual Meetings 2014.
  - Extracted resource estimate cited: up to 1.7 billion barrels (bbl) of recoverable reserves.
  - Proposed maximum government participation option: probably 15 percent.

### Executive-summary findings — petroleum and mining (high level)
- Petroleum prospects and challenges:
  - Uganda poised to become a major oil producer if preconditions met.
  - Joint venture (Tullow Oil, Total E&P Uganda B.V, CNOOC Uganda Ltd) plans a major Uganda Oil Project with government partnership.
  - Up to 1.7 billion barrels (bbl) of recoverable reserves from 6.5 billion bbl of indicated resources; exploration success rate high.
  - Commercialization challenges: infrastructure, regulatory and fiscal issues; oil market developments since mid-2014 complicate project decisions.
  - Legal progress: two new Acts of 2013; first competitive licensing round held in 2015.
- Minerals development:
  - 498 exploration licenses, 37 mining leases, 30 mining leases in production; no large-scale mining at production stage.
  - Two mineral agreements signed; implementation depends on tax changes.
- Cross-cutting fiscal impediments:
  - VAT, withholding taxes under the Income Tax Act (ITA), and income tax rules inhibit development; report emphasizes solutions.

### Upstream petroleum — recommended fiscal design elements
- Components: royalty, production sharing, income tax, and state participation.
- Cost recovery limit:
  - Recommendation: cost recovery limit could be set at 70 percent after deduction of royalty.
- Licensing round bid variables:
  - Bid variables should be limited; either signature bonus or an upper tier of production sharing should be bid variable; other items fixed and non-negotiable.
- Profit-sharing metric:
  - Authorities propose shift from DROP to R-Factor; report supports R-Factor.
  - Proposed progression: government share rises from 50 percent at R-Factor of one to 75 percent at R-Factor of three (interpolated band preferred).
- Income tax on petroleum companies:
  - Corporate income tax rate remains at 30 percent.
  - Recommendation: calculate income tax from gross income comprising combined cost and profit oil with reconciled allowable deductions under ITA.
- State participation:
  - Continue carried interest scheme; government participation costs advanced by contractors and repaid with interest out of government’s participation share without recourse to other government assets.
  - Percentage participation option should be set at a maximum, probably 15 percent.
- Specific recommendations (explicit list):
  - Set crude oil royalty either at a fixed rate of 8 to 12 percent or by sliding scale of DROP.
  - Ensure PFMA provisions on royalty sharing implementable under chosen royalty scheme.
  - Continue with a cost recovery limit, probably at 70 percent.
  - Remove financing charges as a cost recoverable item.
  - Introduce a 15 percent one-time uplift for development costs during the first five years of development expenditure.
  - Adopt the R-Factor scheme for profit petroleum sharing.
  - Calculate income tax on petroleum companies from gross income consisting of both cost and profit oil, applying allowable deductions.

### Royalty, cost recovery, and R-Factor — findings and numeric parameters
- 1999 model PSA royalty tiers (incremental):
  - Up to 2,500 (bpd) — 5.0 (In percent)
  - 2,500 up to 5,000 (bpd) — 7.5 (In percent)
  - 5,000 up to 7,500 (bpd) — 10.0 (In percent)
  - Greater than 7,500 (bpd) — 12.5 (In percent)
- Report favors a general royalty rate of 8 to 12.5 percent for crude oil.
- Draft model PSA 2015 royalty scale (DROP incremental):
  - Up to 25,000 (bpd) — 8 (In percent)
  - 25,000 up to 50,000 (bpd) — 10 (In percent)
  - 50,000 up to 75,000 (bpd) — 12 (In percent)
  - 75,000 up to 100,000 (bpd) — 14 (In percent)
  - 100,000 up to 130,000 (bpd) — 16 (In percent)
  - Greater than 130,000 (bpd) — 18 (In percent)
- Cost-recovery examples:
  - 60 percent cost oil limit implies 40 percent of gross production is profit oil; 45 percent of that to government = 18 percent of gross production if no formal royalty.
  - If formal royalty 12.5 percent and cost oil = 60 percent of post-royalty balance: cost oil = 52.5 percent; minimum government share of profit oil = 15.75; total minimum effective royalty = 12.5 + 15.75 = 28.25 percent.
- Recommendation: increase cost recovery limit to 70 percent in rebalanced model PSA.
- Uplift and financing:
  - Financing costs should not be recoverable; recommend a one-time uplift (recommended 15 percent) for development costs during first five years.

### Fiscal modeling — PSA alternatives, project examples, and key assumptions
- Modeling tool: FAD’s FARI framework.
- Four sets of terms evaluated: PSA EA1A (2012), PSA EA1 (2004), R-Factor Option 1, R-Factor Option 2.
- Stylized fields:
  - Large field: total production 956 MM bbl; project life 27 years.
  - Medium field: total production 264 MM bbl; project life 26 years.
- Price assumption for stylized examples: "US$51/bbl FOB Mombasa, in constant dollars of 2015."
- Large field project economics (selected):
  - Exploration costs $MM 1,250; $/bbl 1.3.
  - Development costs $MM 5,400; $/bbl 5.6.
  - Operating costs $MM 7,648; $/bbl 8.0.
  - Pipeline tariff $MM 11,092; $/bbl 11.6.
  - Total costs $MM 25,940; $/bbl 27.1.
  - Pre-tax IRR 18.9%.
- Medium field project economics (selected):
  - Exploration costs $MM 900; $/bbl 3.4.
  - Development costs $MM 2,500; $/bbl 9.5.
  - Operating costs $MM 1,846; $/bbl 7.0.
  - Pipeline tariff $MM 2,678; $/bbl 11.6.
  - Total costs $MM 8,174; $/bbl 32.4.
  - Pre-tax IRR 9.7%.
- Government revenue and AETR:
  - Undiscounted AETRs:
    - Large project: between 79 and 86 percent.
    - Medium project: between 79 and 83 percent.
  - Discounted AETRs (10 percent discount rate) for large field:
    - 2004 PSA: 118
    - 2012 PSA: 125
    - R-Factor Option 1: 107
    - R-Factor Option 2: 110
  - Post-tax IRR under current price conditions:
    - Large field: 9.2 percent.
    - Medium field: 2.5 percent.
- Progressivity and breakeven:
  - R-Factor options are more progressive than existing PSAs; suggested minimum and maximum government shares 50 and 75 percent across R-Factor of one to three.
  - Breakeven impacts vary by field size: R-Factor reduces breakeven for large fields but can raise breakeven for smaller fields with low production rates.

### Sensitivity and EMV analysis — price scenarios and implied bid bonuses
- Two price scenarios: $51/bbl and $80/bbl.
- Under $51/bbl:
  - Decrease minimum government share from 50 to 40 percent: Government NPV10 falls by 4 percent, or $147 million; post-tax IRR increases from 8.2 to 8.9 percent.
  - Increase minimum government share from 50 to 60 percent: Government revenue increases by $163 million, or 5 percent; post-tax IRR falls to 7.3 percent.
- Under $80/bbl:
  - A 10 point increase in maximum government share increases government revenue by $268 million and reduces post-tax IRR from 14.6 to 13.8 percent.
  - A 10 percent decrease in maximum government share reduces government revenue by $230 million and increases post-tax IRR to 15.4 percent.
- EMV (expected monetary value) and implied bid bonus (exploration success probability assumed 85 percent; company discount rate 12.5%; oil price $80/bbl):
  - Large oil field (R-Factor Option 1): NPV failure -1,209; NPV success 492; EMV (implied bid bonus) 236.
  - Large oil field (R-Factor Option 2): NPV failure -1,209; NPV success 409; EMV (implied bid bonus) 166.
  - Medium oil field (R-Factor Option 1): NPV failure -880; NPV success -387; EMV -461.
  - Medium oil field (R-Factor Option 2): NPV failure -880; NPV success -394; EMV -467.

### International comparisons and simulated price analysis
- Comparator countries include Chad, Sudan, DRC, Mozambique, Tanzania, Kenya, Australia, Colombia.
- AETR placement:
  - 2012 and 2004 PSAs are at higher end of sample; R-Factor options mid-range.
- Simulated price analysis:
  - Price simulations impose bounds $20/bbl and $200/bbl; autoregressive model used; repeated hundreds of times.
  - Example ordering for large field mean post-tax IRR and tax-induced probability below 12.5%:
    - Tanzania: mean 6.4778, tax-induced probability 82.
    - Uganda EA1 (2012): mean 8.1767, tax-induced probability 72.
    - Uganda R-Factor Option 1: mean 11.253, tax-induced probability 54.
    - Uganda R-Factor Option 2: mean 10.656, tax-induced probability 56.
    - Australia PRRT: mean 17.838, tax-induced probability 12.

### Project configuration, sequencing, and midstream issues
- Project components: upstream production (EA1, EA2, EA3A), early production, refinery, export pipeline.
- Reported recoverable reserves: about 1.2 to 1.7 billion bbl across upstream.
- Refinery plan: initial 30,000 bpd rising to 60,000 bpd.
- Pipeline:
  - Capacity modeled: 210,000 bpd.
  - Approximate length: 1,400 km; ~40 percent in Uganda.
  - Pipeline must be heated; Uganda expects a 15 percent fully paid equity interest in pipeline company.
  - Pipeline tariff modeled to yield a real post-tax rate of return of 7.5 percent (simulation assumption).
- Recommendations on pricing and access:
  - Confirm definition of delivery point for valuation.
  - Determine pipeline tariff formula for netback pricing.
  - Confirm pricing for crude input to refinery and refinery output.
  - Limit exclusivity in transportation infrastructure to minimum necessary to induce investment; ensure third-party access in long term.
- Income taxation of midstream:
  - Pipeline and refinery subject to normal ITA rules; no special income tax treatment or tax holidays recommended.
  - Depreciation rates (Sixth Schedule):
    - Refinery plant and equipment: 30 percent declining balance.
    - Pipeline: 20 percent declining balance.
  - Kenya pipeline depreciation: 12.5 percent declining balance.
  - Recommendation: do not grant tax holidays to pipeline or refinery.

### Project-wide financials and government revenue projections (price assumption $80/bbl FOB Mombasa)
- Price used for full-project analysis: $80/bbl FOB Mombasa (project expected to commence production and operations in 2019).
- Total project pre-tax net cash flow (NCF) over life: almost $98 billion.
- Total project pre-tax IRR: 23.4 percent.
- Pipeline (Uganda portion) key figures:
  - Capacity daily: 210 Mbopd
  - Total crude oil throughput: 872 MMBOE
  - Operation years: 21
  - Capital costs $ million 3,621; $/Bbl 4.2
  - Operating costs $ million 1,728; $/Bbl 2.0
  - Total $ million 5,349; $/Bbl 6.1
- Refinery key figures:
  - Initial capacity rising to 60 Mbopd
  - Total crude oil processed: 471 MMBOE
  - Operation years: 27
  - Capital costs $ million 2,268; $/Bbl 4.8
  - Operating costs $ million 1,212; $/Bbl 2.6
  - Cost of crude oil processed $ million 32,218; $/Bbl 68.4
  - Total $ million 35,698; $/Bbl 75.8
- Aggregate financial metrics (selected NPV and rates):
  - Total upstream project pre-tax NCF: 70,419 (0%); 12,726 (10%); 8,204 (12.5%).
  - Upstream government revenue: 55,720 (0%); 12,290 (10%); 8,909 (12.5%).
  - Total project pre-tax NCF: 98,053 (0%); 16,725 (10%); 10,689 (12.5%).
  - Government revenue (total project): 71,663 (0%); 14,781 (10%); 10,550 (12.5%).
  - Total project AETR: 73% (0%); 88% (10%); 99% (12.5%).
  - Total project post-tax IRR: 13.7% (0%); 10.0% (10%); 7.5% (12.5%).
- Government revenue projection summary:
  - Government revenue estimated in excess of $60-70 billion over 27 years.
  - Sensitivity: $20/bbl reduction in price reduces government revenue by more than 35 percent in NPV terms (discount 10%); 20 percent reduction in production decreases revenue by about 25 percent.

### Mining and minerals fiscal regime — principal design points and numeric rules
- Legislation and licenses:
  - Primary law: Mining Act of 2003.
  - Licenses: prospecting, exploration, retention, mining lease, location license.
  - Exploration licenses: up to 3 years with two 2-year extensions (maximum 7 years).
  - Mining leases: initial 21 years or life of ore body; one renewal up to 15 years or life of ore body.
- Royalties:
  - High-value minerals: ad valorem on gross value based on prevailing market price.
  - Rates (Third Schedule, increased 2011): 5 percent for precious metals and base metals; 10 percent for precious stones.
  - Other minerals: specific rates by weight (e.g., UGX 10,000 per ton for phosphate).
  - Recommendation: define gross value as gross revenues from first sale or FOB export value if exported without sale; net smelter return if sent to a smelter or refinery.
  - Require mineral companies to self-assess monthly royalty payments.
- Income tax for mining companies:
  - Corporate income tax sliding scale: minimum rate 25 percent and maximum rate 45 percent (Part II Third Schedule of ITA).
  - Sliding scale formula: 70 – 1500/X, where X is ratio of chargeable income before any net interest expense to gross revenue (expressed as a percentage point).
  - Recommendation: retain variable rate and define profitability ratio as ratio of chargeable income before any net interest expense to gross revenue.
- Other mining fiscal issues:
  - Prefund or guarantee mine rehabilitation and closure costs; preferred: escrow account under joint control for prefunding (tax-deductible deposits).
  - Improve clarity on royalty valuation, related-party price adjustments, and move from Commissioner-assessed to self-assessed monthly royalties.

### Corporate tax base, deductions, ring-fencing, and transfer rules
- Petroleum corporate tax base:
  - 2010 statutory design treated contractor taxed on share of profit oil; report prefers reverting to pre-2010 approach — chargeable income calculated under normal ITA rules (both cost and profit oil aggregated as gross income) with sector-specific deduction rules.
  - Ring-fencing: recommend ring-fence by license area for petroleum and mining operations, with limited exceptions.
- Exploration and development expenditure:
  - Harmonize rules for exploration and development across mining and petroleum; include common rules in Part IXA.
  - Depreciation alignment: adopt mining depreciation rule for petroleum (mining depreciation rule seen as appropriate).
- Decommissioning and rehabilitation:
  - Allow current tax deduction for payments to approved escrow account; align ITA with PEDPA on decommissioning reserves.
- Thin capitalization:
  - Current foreign debt-to-equity limit: 1 to 1; prior allowed 2 to 1.
  - Recommendation: extend limit to all loans and increase allowable debt-to-equity ratio to 1.5 to 1.
- Transfers, farm-outs, and indirect transfers:
  - Provide clear rules for characterization of farm-outs, treatment of reimbursements, and deduction rights.
  - Treat gains on indirect transfers as taxable; extend s 79(g) to apply to unit trusts and partnerships; ensure meaning of “immovable property” includes mining and petroleum rights.
  - Strengthen administrative discovery and collection (reporting obligations for change in control; treat holder as agent for tax collection where appropriate).

### International tax, subcontractors, and tax treaties
- Taxation of non-resident subcontractors:
  - Benchmark: tax Ugandan-source technical fees.
  - If fees attributable to a Ugandan branch: tax on net basis at normal corporate rate (ordinary assessment).
  - If no branch: final withholding tax on gross amount.
  - Current withholding rate s 85: 15 percent on gross; recommendation: review and consider reducing to 10 percent to align with treaty limits.
- Source rules and branch definition:
  - Modernize source rules for technical fees; align with place of utilization and branch/permanent establishment concepts.
  - Definition of “branch” (s 78) should be modernized — adopt services branch rule based on Article 5(3)(b) of UN Model: furnishing services through personnel in Uganda aggregated more than 183 days in any 12-month period constitutes branch.
- Treaties:
  - Ensure future tax treaties preserve Uganda’s taxing rights on lease payments, technical fees, and gains on indirect transfers.

### VAT treatment and prioritized reforms (integrated package)
- Overarching goal: VAT should not raise revenue from exploration and development phases; should not hinder investment.
- Critical reforms to be addressed as an integrated package in the year’s budget proposals:
  1. Allow companies to register voluntarily for VAT during exploration and development phases; allow companies constructing refineries and pipelines to register during construction phase of midstream facilities.
  2. Exempt imports by a subcontractor from VAT if imports are for direct and exclusive use in a resource project, with surveillance measures to ensure exclusive use.
  3. Implement a properly functioning refund system for resource companies; interim measure: adopt a remission scheme for domestic first-tier subcontractors where VAT charged on supplies to resource companies is deemed paid by the companies.
  4. Restore the input credit for the reverse charge (s 5(c) repeal reversal); urgent prior to issuance of RFP for first licensing round.
  5. Repeal the VAT exemption for petroleum products and reduce excises on these products.
- VAT on petroleum products — numeric illustration (Table 9 figures preserved):
  - Gasoline
    - Retail Price (UGX per liter): 3,600
    - Excise (UGX per liter): 950
    - Embedded VAT (18 percent)1/: 549
    - True Excise (UGX per liter): 401
  - Diesel
    - Retail Price (UGX per liter): 2,800
    - Excise (UGX per liter): 630
    - Embedded VAT (18 percent)1/: 427
    - True Excise (UGX per liter): 203
  - Note 1/: 15.25 percent on a tax inclusive basis
- Recommended VAT interim and transition measures:
  - Accounts-based remission for first-tier domestic suppliers as interim support.
  - Alternative: carryforward input tax credits with interest; for petroleum companies consider making accumulated credit first claim on government’s share of profit oil (would require PSA amendment).

### Fiscal stability clauses and stamp duties
- Fiscal stability:
  - No statutory provision in PEDPA or Mining Act for government fiscal stability assurances; assurances have been given in PSAs and a mineral agreement.
  - Recommendation: amend Mining Act to permit fiscal stability assurances if conditions met; time limit five years from start of commercial production; cover only income and withholding tax rates, royalty rates, and cost recovery rules for capital expenditure.
- Stamp duties:
  - Principal ad valorem duties affecting resource companies:
    - 0.5 percent duty on new share capital
    - 0.5 percent duty on debentures
    - 1 percent duty on total value of lease or hire/purchase agreement
    - 1 percent of the total value of a transfer of shares (0.5 percent if company is listed)
  - Recommendation: consider eliminating ad valorem stamp duties that apply to financing transactions and increased equity.

*Source: IMF technical assistance mission aide‑mémoire and executive summary (Preface, Executive Summary, and chapters/excerpts from cr17367).*

### Preface ................................................................................................................

### Preface

### Mission context and participants
- Request from the Delegation of the Republic of Uganda at the Annual Meetings 2014 led to a technical assistance mission to Kampala and Entebbe during the period February 25 to March 10 2015 to provide advice on extractive industry (EI) fiscal regimes.
- The mission followed approval by the Steering Committee of the IMF’s Topical Trust Fund on Managing Natural Resource Wealth of a full project on EI Fiscal regimes in Uganda (MNRW TTF Module 1 Project).
- Mission leadership and team: Philip Daniel, Diego Mesa Puyo (both FAD), Emil M. Sunley (FAD External Expert), and Lee Burns (LEG Expert).
- The aide-mémoire contains analysis and conclusions of the mission, subject to review at IMF headquarters.
- The mission engaged with officials from MFPED, MEMD, URA, Bank of Uganda, civil society, international oil companies, professional advisors, and donor representatives.

### Key project-level dates and figures
- Mission visit: February 25 to March 10 2015.
- Prior request: Annual Meetings 2014.
- Extracted resource estimate cited: up to 1.7 billion barrels (bbl) of recoverable reserves.
- Proposed maximum government participation option: probably 15 percent.

### Acknowledgements (summary)
- Principal interacting institutions: Ministry of Finance, Planning and Economic Development (MFPED); Ministry of Energy and Minerals Development (MEMD); Uganda Revenue Authority (URA); Bank of Uganda; Technical Group on Petroleum (MFPED, MEMD, URA, Ministry of Justice).
- Engagements with civil society: Africa Initiative for Energy Governance, Natural Resource Governance Institute.
- Private sector meetings: Tullow Uganda, Total E & P Uganda, CNOOC Uganda, PwC, Deloitte, Uganda Chamber of Mines and Petroleum, Kampala Associated Advocates.
- IMF Resident Representative guidance: Ms. Ana Lucia Coronel.

### Executive-summary findings: petroleum and mining (bulleted)
- Petroleum prospects and challenges:
  - Uganda is poised to become a major oil producer if key preconditions are met.
  - A joint venture of three international companies plans a major Uganda Oil Project, in partnership with the government.
  - Up to 1.7 billion barrels (bbl) of recoverable reserves have been discovered with a high exploration success rate.
  - Significant commercialization challenges: infrastructure for commercialization, and outstanding regulatory and fiscal issues.
  - Oil market developments since mid-2014 have created a difficult environment for project decisions.
  - Legal progress: two new Acts of 2013; first competitive licensing round being held in 2015.
- Minerals development:
  - Large number of exploration and mining rights issued, many with little work in progress.
  - Two mineral agreements recently signed; implementation depends upon tax changes since agreements do not fully conform to tax law provisions.
- Cross-cutting fiscal impediments:
  - VAT, withholding taxes under the Income Tax Act (ITA), and income tax rules present challenges inhibiting development; report emphasizes solutions.

### Upstream petroleum — substantive recommendations and design elements
- Components of fiscal terms:
  - Upstream fiscal terms combine royalty, production sharing, income tax and state participation.
  - Existing PSAs will govern the Uganda Oil project and provide substantial revenues to government when production starts.
  - New Model PSA for the licensing round will be geared towards attraction of exploration commitments and significant revenue to government on commercial development.
- Royalty, cost oil limit, and minimum government profit oil share interact to produce the minimum “effective royalty”; adjustments can account for bonus bids and higher shares in successful projects; royalty design must account for distribution to local governments.
- Cost recovery limit recommendation:
  - The cost recovery limit could be set at 70 percent after deduction of royalty.
- Licensing round bid variables:
  - In addition to work program, either a signature bonus or an upper tier of production sharing should form the bid variable in the licensing round; all other items fixed and non-negotiable.
- Shift in profit-sharing metric:
  - Authorities propose to shift from a DROP (daily rate of production) scale to an R-Factor (payback ratio) scale; the report supports this change as it automatically accounts for cost, prices and volumes without more data than for DROP.
  - Proposed government share progression under R-Factor scheme: government’s share rises progressively (by formula) after achievement of initial payback (R-Factor of one) from 50 percent to 75 percent when the R-Factor reaches three.
- Income tax on petroleum companies:
  - Rate remains at 30 percent but legislative implementation requires reform.
  - Combined cost and profit oil should comprise gross income; reconciliation of allowable tax deductions with cost recovery rules is necessary though differences may be retained for policy reasons.
- State participation:
  - Continuation of a carried interest scheme is appropriate: government participation costs advanced by private contractors and repaid with interest out of the government’s participation share of oil, without recourse to other government assets.
  - Percentage participation option should be set at a maximum, probably 15 percent.

### Fiscal issues for the Uganda Oil Project — specific analysis and options
- Linked decisions and tax/pricing issues:
  - VAT and income tax issues require solutions for project progression.
  - Upstream delivery-point pricing for exported oil: determined by a netback from the seaport price minus pipeline transportation tariff.
  - Options for transportation tariff determination are outlined; both Uganda and contractors seek to maximize value at the upstream delivery point.
  - Once export price set, it benchmarks the price of oil entering the proposed refinery; if the refinery can sell products at import parity prices, the combination (pipeline export and domestic refining) is economically feasible per the report’s analysis.
- Cross-border allocation and third party access:
  - Attention drawn to cross-border allocation issues and need for third party access to infrastructure, while ensuring initial investors retain sufficient capacity.
- Tax treatment of midstream facilities:
  - Midstream facilities (pipeline and refinery) should not receive special income tax treatment; they will be subject to income tax as normal processing or transportation businesses.
  - Tax holidays are not necessary.
  - Option exists for a common tax scheme with the transit country for the pipeline, but applying national tax systems with apportionment of costs and revenues is suggested as simpler.

### Mining and minerals fiscal regime — findings and recommendations
- Royalty base and valuation:
  - Uganda’s royalty for high-value minerals is assessed on the gross value of the mineral based on the prevailing market price.
  - Ambiguity exists on whether the base for assessing royalty is: value of the mineral contained in the ore at the mine mouth; contained in the first product sold or exported (such as a concentrate); or the value of minerals recoverable.
  - For minerals sent to a smelter or refinery, gross value would be the net smelter return; for other minerals subject to ad valorem rates, value would be gross revenues from the first sale or FOB export value if exported without sale.
- Income tax rates and structure:
  - For a company carrying on mining operations, the income tax rate is sliding scale with a minimum rate of 25 percent and a maximum rate of 45 percent.
  - For non-mining companies, the corporate tax rate is 30 percent.
  - The variable rate is designed to impose a lower-than-average rate of tax in years of poor relative profitability offset by a higher-than-average rate of tax in years of high relative profitability.
  - Recommendation: retain the variable rate.
- Profitability ratio and debt concerns:
  - To address excessive use of debt, the profitability ratio should be defined as the ratio of chargeable income before any net interest expense to gross revenue.
- Fiscal stability for mining:
  - For mining, the power to make a fiscal stability assurance, if needed, should be made explicit in legislation.

### Common fiscal/tax issues — income tax and international tax rules
- Uniform rules for resource company chargeable income:
  - Include uniform rules in the ITA by applying a modified Part IXA to all resource companies with specific deduction rules for exploration, development, rehabilitation (decommissioning), and social infrastructure expenditures.
  - For petroleum companies, revert to the pre-2010 design of Part IXA: tax based on chargeable income calculated in the usual way, rather than being based on profit oil.
- International tax modernization:
  - Withholding tax rules for technical fees paid to non-resident subcontractors need review.
  - Specific actions: modernize the source rules for technical fees and the definition of “branch”; apply net taxation to technical fees attributable to a Ugandan branch of a non-resident; review the rate of withholding tax.
  - Future tax treaties must preserve Uganda’s taxing rights in relation to lease payments, technical fees, and gains on indirect transfers.

### VAT treatment of the petroleum and mining chain — prioritized reforms
- Overarching goal:
  - VAT should not raise revenue from exploration and development phases; it should not hinder investment.
- Critical reforms to be addressed as an integrated package in the year’s budget proposals:
  1. Allow companies to register voluntarily for VAT during exploration and development phases of a resource project; allow companies constructing refineries and pipelines to register during the construction phase of midstream facilities.
  2. Exempt imports by a subcontractor from VAT if the imports are for direct and exclusive use in a resource project, with proper surveillance measures to ensure exclusive use.
  3. Work towards implementing a properly functioning refund system for resource companies; short-term interim measure: adopt a remission scheme for domestic suppliers who are first-tier subcontractors to a resource project under which VAT charged on supplies to resource companies is deemed to have been paid by the companies.
  4. Restore the input credit for the reverse charge.
  5. Repeal the VAT exemption for petroleum products and reduce the excises on these products.

*Source: IMF technical assistance mission aide‑mémoire and executive summary (Preface and Executive Summary sections).*

### 1.      Uganda has the potential to become a major oil producer. The existence of significant

### cr17367 - 1.      Uganda has the potential to become a major oil producer. The existence of significant

### A. Oil discoveries, project structure, and timelines
- Existence of significant oil discoveries was confirmed in 2006; a moratorium on further licensing was placed in 2007.  
- National Oil and Gas policy (NOGP) published in 2008.  
- Two petroleum Acts entered into force in 2013: the Petroleum Exploration, Development and Production Act (PEDPA) and the Petroleum Refining, Conversion, Transmission and Midstream Storage Act.  
- Moratorium lifted in February 2015 with announcement of Uganda’s first competitive licensing round for six blocks. The model Production Sharing Agreement (PSA) is undergoing revision for this licensing round.  
- A joint venture of three international companies (Tullow Oil, Total E&P Uganda B.V, and China National Offshore Oil Corporation (CNOOC) Uganda Ltd) each holds a one-third interest in blocks with discoveries; each is an operator for at least one block.  
- Current estimates indicate up to 1.7 billion barrels (bbl) of recoverable reserves, from 6.5 billion bbl of indicated resources (oil in place).  
- JV and government plan combined crude oil production from 15 discoveries in four Exploration Areas (EA), to be sold partly to a domestic refinery and partly for export via a pipeline to the coast of Kenya or Tanzania.  
- Development plans for the discoveries were submitted in 2014; so far only the plan for the Kingfisher discovery in EA3A has been approved and only one production license (PL) has been issued.  
- Once PLs are granted, it may take up to two years for commercial and financial arrangements to be secured, for an engineering, procurement and construction contract (EPCC) to be negotiated and settled, then to complete front end engineering and design (FEED), and for the JV to take a final investment decision (FID). Thereafter it will take three to four years until the full project is commissioned and begins production, though there are plans for earlier small-scale production to fuel local electricity generation.  
- The oil discovered so far is “paraffinic” (high wax content); its viscosity will require the export pipeline to be electrically heated throughout, increasing pipeline capital and operating costs.

### B. Exploration success and commercialization challenges
- Recorded rate of success in discovery by exploration wells exceeds 85 percent.  
- Discovery success rate: 116 deep wells drilled in the Albertine Graben; 102 of these wells have encountered hydrocarbons in the subsurface.  
- Challenges mirror those for gas: reserves are remote from large domestic or international markets, requiring coordinated development of major transport or processing facilities.

### C. Mining and minerals development
- Airborne geophysical surveys in 2010 and 2011 indicated reported resources of at least 50 mineral commodities.  
- Companies hold 498 exploration licenses and 37 mining leases; 30 mining leases are in production.  
- Current hard mineral production includes hematite iron ore, cement, kaolin, wolfram, and vermiculite. Uganda has no large-scale mining projects at the production stage.  
- Mining legislation dates back to 2003.  
- Two projects with mining leases at the development stage: Kilembe copper-cobalt mine concession agreement signed in 2013 (including cobalt processing facilities) and Sukulu phosphate and steel project mineral development agreement signed in December 2014 with Guangzhou Dongsong Group.  
- Future large-scale projects could include iron ore, tin, and tungsten. There is potential for geothermal energy.  
- The largest mineral export by value is gold, all mined in small-scale operations. Mining faces challenges of land tenure and community opposition; problems of access to land for exploration have caused many licenses to remain dormant.

### D. Project purpose, scope, and capacity building (MNRW TTF Uganda project)
- The authorities requested support through a project on extractive industries (EI) fiscal regimes under the IMF’s Topical Trust Fund on Managing Natural Resource Wealth (MNRW TTF).  
- Project delivered by IMF’s Fiscal Affairs Department (FAD) in collaboration with the Legal Department (LEG), building on past technical assistance and cooperating with development partners including NORAD Oil for Development Programme and the EI Technical Advisory facility of the World Bank.  
- MNRW TTF concentration in five modules: (1) extractive industries (EI) fiscal regimes, licensing and, contracting; (2) EI revenue administration; (3) EI macro-fiscal policies and public financial management; (4) EI asset and liability management; and (5) statistics for EI. This diagnostic mission is the first activity under module 1, EI fiscal regimes, licensing and, contracting.  
- Purpose: support government to develop EI fiscal regimes that secure a rising share of benefits from profitable projects while creating a stable and attractive climate for private investment, and build authorities’ capacity to analyze and design fiscal regimes for EI. Specific aims: (1) review existing petroleum and mining fiscal regimes and design/implement reforms as necessary; (2) address midstream and downstream fiscal issues to enable a major petroleum project for domestic processing and/or export to proceed; and (3) improve capacity of ministries to evaluate and design fiscal regimes for EI.  
- Project designed over an 18–month period with multiple visits by FAD staff, FAD experts and an external legal expert; may include workshops to train government officials on FAD’s fiscal analysis of resources industries (FARI) model. The model is intended to be transferred to Ugandan authorities upon formal request to FAD.  
- Partners with the IMF in the MNRW TTF: Norway (Oil for Development), the European Commission, Australia, Switzerland (SECO), the Netherlands, Kuwait and Oman.

### E. Fiscal priorities and analytical work
- Authorities prioritized fiscal issues for development of the Uganda Oil Project and the new licensing round:  
  - Tax matters: (i) application of value added tax (VAT) to the chain of EI activities, transportation and processing, and sales; (ii) application of withholding taxes on technical services acquired from nonresidents; and (iii) provisions of the Income Tax Act (ITA) for petroleum (and also for mining).  
  - Production-sharing: (iv) terms of the new model PSA required for the 2015 licensing round.  
- The mission constructed preliminary models using FAD’s FARI system for: the upstream fiscal regime with project examples; the potential linked project including a pipeline and refinery; and the fiscal regime for mining with a potential iron ore project. Modeling outputs are preliminary and subject to caveats.  
- Draft report coverage: Chapter II upstream petroleum fiscal regime; Chapter III fiscal issues for the proposed Uganda Oil Project (except general tax matters); Chapter IV fiscal regime for mining and minerals development; Chapter V tax issues common to oil, gas and mining, including application of VAT.  
- Transparency priorities: support for Uganda’s intention in the NOGP to become a candidate in the Extractive Industries Transparency Initiative and for public disclosure of PSAs as recommended in the IMF Guide on Resource Revenue Transparency and in the consultation draft of the Natural Resource Revenue Management Pillar of the new Fiscal Transparency Code.

### F. Upstream petroleum legislation and licensing regime (PEDPA 2013)
- PEDPA 2013 repealed the Petroleum Exploration and Production Act of 1985; vests all rights to petroleum in the ground in the government on behalf of the Republic of Uganda.  
- PEDPA establishes two institutions: the Petroleum Authority of Uganda as regulator and a National Oil Company (NATOIL) to be incorporated under the Companies Act as the commercial arm of government to hold state participation shares.  
- PEDPA covers all stages from award of rights through abandonment and decommissioning and explicitly continues license rights granted under the previous law as if granted under PEDPA.  
- Licensing scheme: non-exclusive reconnaissance licenses, exploration licenses (EL), and production licenses (PL) with transition rules after discovery. ELs typically divided into three exploration periods of two years each, with availability of extension for an appraisal period after a discovery. EL holders must relinquish 50 percent of their remaining area (excluding any discovery area) at each renewal of the EL. Only an EL holder can apply for a PL except where EL holder declines to develop a discovery. PL includes obligation to prepare and fund an abandonment and decommissioning plan.  
- PEDPA allows agreements in combination with ELs or PLs; s6 permits government to enter into an agreement governing the grant of a license. The Act calls for a model PSA to be submitted to Cabinet for approval and then laid before Parliament; the model “shall guide negotiations of any future agreements.” The presumption favors a production sharing regime but other fiscal schemes remain possible.  
- New area opening: minister must submit a report to Parliament and make a public announcement of new areas to be opened for exploration, with provision for public review and comment. Presumption that competitive bidding will be followed for allocation of ELs and PLs, with exceptions (e.g., invitations to bid made three times with no applications; reservoir extending beyond a license area to an unlicensed block; or to enhance state participating interest). Direct applications must be published (s54).  
- ELs require work program and expenditure commitments, fees, bonuses, and perhaps a state participation option. A signature bonus is required upon granting either an EL or PL; the signature bonus is a “single, non-recoverable lump sum payment.” When announcing areas for ELs, the minister, with Cabinet approval, specifies the maximum state participation share; the form, timing, or financial terms of the option are not established in PEDPA.

### G. 2015 licensing round specifics, fiscal implications, and recommendations
- MEMD published notice of request for qualification on February 26, 2015, to license six blocks. The application and pre-qualification process was set to be complete with issue of an RFP and bidding documents to qualified applicants on July 20, 2015. No time period was set for completion of the bidding process and announcement of winning bids or allocations. Two of the blocks may be open to stratigraphic licensing.  
- The licensing round has significant fiscal implications: the bonus and state participation results will eventually be of direct fiscal effect; preparations of a new model agreement (including fiscal provisions) and solutions to anomalies in the tax system are urgent.  
- Issues for the new licensing round include completion of a model PSA and resolution of tax issues: revision of petroleum provisions of the ITA Part IX; clarity on application of withholding tax under the ITA on payments to non-residents for technical services and associated issues with the definition of “branch” in Uganda; and reform of rules for application of VAT to the chain of EI activities.  
- Prequalification criteria are available on application (with a fee) and have not been published; applicants asked to submit pre-qualification applications by May 29, 2015. It is unclear whether prequalification will result in a single class of qualification or multiple classes (e.g., participants vs. operators). Authorities might consider making prequalification criteria public.  
- Before issue of bidding documents, the bidding process, criteria, variables, and weighting must be specified. A clear auction process is preferable but may not be feasible if a very limited number of applicants is expected. Bid variables should be limited in number; if work program variables are included, fiscal terms should be non-biddable (or limited to one item such as signature bonus or top tier of production sharing). A weighting of 50/50 between two variables would work, though alternatives could be justified.

Recommendations
- Combine completion of a new model PSA and necessary tax reforms before issuance of requests for proposals in the licensing round for petroleum.  
- Consider publication of prequalification criteria.  
- Determine the bidding process, with preference for an open auction with no more than two bid variables.  

*IMF staff report content as provided in the source PDF.*

### 23.      A model PSA was last issued in 1999 and the government now proposes a full

### 23.      A model PSA was last issued in 1999 and the government now proposes a full overhaul.

### Proposed overhaul and context
- The new scheme under consideration will retain the combination of royalty, production sharing, income tax and state participation.
- Bidding, perhaps for a signature bonus, may assume greater importance.
- The production-sharing scheme is likely to adopt the R-Factor (or payback ratio) scale for sharing between the contractor and the government.
- ITA provisions for petroleum were introduced in 2010 in an apparent attempt to make the contractor’s share of profit oil the net chargeable income for application of the corporate tax rate.
- Two PSAs were signed in 2012 applying to Exploration Area EA1A and to a block called Kanywataba in EA3A (latter relinquished). The new model PSA is required for the 2015 licensing round.
- The EA1 and EA1A PSAs are included in the economic evaluation of petroleum terms but are not assessed in detail here.
- Uganda has secured very favorable terms in PSAs, particularly the 2012 PSAs, but EA1A was tailored to known discoveries in an oil price environment more favorable than early 2015.
- The government wishes to explore the R-Factor scheme; the report endorses this decision if a production-sharing framework is retained.

### Production sharing basics (findings)
- Under the Constitution and the PEDPA 2013, the government always retains the rights to resources in the ground.
- Difference between tax-and-royalty and production-sharing:
  - Under production-sharing, petroleum produced is divided between government and investors according to the agreed scale; contractor retains production share to replace a service fee and has no right to payment if discovery/development does not occur.
  - Under tax-and-royalty the licensee takes ownership of petroleum produced subject to payment of royalty and tax liabilities to government.
  - If the contractor markets the government’s share on its behalf, the arrangement becomes a “proceeds-sharing” scheme, similar in practical effect to tax-and-royalty.
- Production-sharing mechanics:
  - (1) PSA may provide for an explicit royalty payment (in accordance with s154 of the PEDPA).
  - (2) A portion of total production (after royalty) can be retained by the contractor to recover costs (“cost oil”).
  - (3) Remaining oil (including any surplus of cost oil) is “profit oil” and is divided per PSA formula.
  - (4) Contractor pays income tax.
- Under a PSA the government’s profit oil is typically the largest piece of the government’s overall take; income tax and royalty then follow, and sometimes a substantial bonus is obtainable.
- Objective of progressivity: ensure government share rises with overall project profitability. DROP (daily rate of production) was used earlier as proxy for profitability but is inadequate; modern sharing uses cumulative profitability—typically R-Factor or rate of return (ROR).
- Progressive schemes can substitute for direct targeting of resource rent; refunding or sharing of losses (as in Norway, Canada, UK, Australia) is less practicable in Uganda and most developing countries. A progressive scheme has advantages for Uganda.

### Fiscal timing and trade-offs
- There is a trade-off between maximizing early government revenue and achieving the largest feasible share over whole project life; earlier PSAs favored early revenue.
- The new licensing round aims to diversify portfolio and attract exploration that produces later, allowing the fiscal regime to trade early revenue for late and adopt a more progressive structure.

### Royalty (findings and recommendations)
- PEDPA calls for royalty; issue is form to take.
- 1999 model provided a scale of royalty rising to 12.5 percent for very small fields as follows (Table reproduced from source):
  - Up to 2,500 (bpd) — 5.0 (In percent)
  - 2,500 up to 5,000 (bpd) — 7.5 (In percent)
  - 5,000 up to 7,500 (bpd) — 10.0 (In percent)
  - Greater than 7,500 (bpd) — 12.5 (In percent)
- Uncertainty existed whether rates applied incrementally or to all production once triggered; settled in favor of incremental scheme in the PSA for EA1A (tiers and rates replicate 1999 model). Royalty applies by contract area (aggregate if more than one field).
- Report favors a general royalty rate of 8 to 12.5 percent for crude oil, fitting international standards where royalties are applied.
- Under incremental 1999 scale, suggested rates are quickly reached during first year of production in any contemplated field; royalty loss over project life negligible in present value.
- Incremental scheme may be useful late in field life if a single field remains from original contract area because reducing royalty could prolong field life without discretionary remission.
- Draft model PSA of 2015 proposed alternative incremental DROP scale (Table reproduced from source):
  - Up to 25,000 (bpd) — 8 (In percent)
  - 25,000 up to 50,000 (bpd) — 10 (In percent)
  - 50,000 up to 75,000 (bpd) — 12 (In percent)
  - 75,000 up to 100,000 (bpd) — 14 (In percent)
  - 100,000 up to 130,000 (bpd) — 16 (In percent)
  - Greater than 130,000 (bpd) — 18 (In percent)
- In example in Figure 2, an average royalty of 10 percent is triggered in the first four years of production under the draft 2015 scale.
- Additional royalty by reference to cumulative production was added to EA1A and Kanywataba PSAs in 2012; mission understood this is unique to revision in 2012 and is not intended for the new model PSA. Report concurs with proposal not to include additional royalty in the future because it is regressive and additional revenue can be obtained more efficiently from R-Factor sharing.
- PFMA 2015 provides for distribution of six percentage points of royalty revenues to local governments; this may influence choice of royalty structure. PFMA (s 75, Schedule 6) allocates half of local government amount to local governments where “production or impact” is located, and half to all governments, including those where production is located. One percentage point of remaining central government receipts of royalties will be granted to a “gazetted cultural or traditional institution.”
- Flat rate royalty may be simpler given PFMA distribution complexities and localities’ difficulty managing sliding-scale variations.

### Cost recovery rules (findings and policy suggestions)
- Limitation on cost oil functions as additional tier of royalty on gross production while limit applies.
- Example calculations (from source):
  - The 60 percent limit in EA1 implies that 40 percent of gross production is treated as profit oil, of which 45 percent goes to the government: 18 percent of gross production if there is no formal royalty.
  - If formal royalty is 12.5 percent and cost oil is calculated only from the balance after royalty, then cost oil = 60 percent of 87.5 percent = 52.5 percent, and minimum share of profit oil to government = 15.75.
  - Total minimum share, or effective royalty to government, = 12.5 plus 15.75 equals 28.25 percent. This coincides with percentage implied by minimum royalty and cost-recovery scheme in the 1999 model PSA.
- For a rebalanced model PSA with R-Factor, a higher cost oil limit is appropriate; shifting limit to 70 percent creates room for bonus bidding and for higher sharing rates in profitable projects since initial risk to contractor is reduced.
- Combination of modest flat-rate royalty (first option) or royalty structured not to reach maximum early (second option), a higher cost recovery limit, and R-Factor scheme reduce the minimum effective royalty rate, lessening fiscal burden on less profitable projects.
- Financing costs should not be recoverable; a one-time uplift could be substituted.
  - Rationale: PSA analogous to unincorporated joint venture where each party finances irrespective of source and does not charge interest to the venture; PSA calculations are on cash flows of total funds, not returns to equity; recovery of interest is not warranted.
  - Uplift on initial exploration and development capital costs is consistent with cash flow treatment and does not discriminate between equity and debt.
- Uplift is modest recompense for time value of money and probably less costly in government revenue terms than permitting recovery of financing costs; it accelerates/increases cost recovery, reduces contractor risk, increases EMV in exploration risk calculation, raises possibility of positive bonus bids, and brings forward triggering of higher tiers under R-Factor.

### Sharing of profit oil: R-Factor system (findings and recommendations)
- Authorities favor switch to R-Factor system; report concurs.
- R-Factor defined as simple cumulative ratio of revenue net of operating costs to exploration and development costs outlaid; when combined with uplift, time value of money is substantially taken into account.
- Formula description: R-Factor = (cumulative revenues including contractor’s receipts of both profit and cost oil, including any recovery of uplift and adjustments for net credits to the cost recovery account) divided by cumulative exploration and development costs (as per text).
- Data required for R-Factor calculation are same as those used in DROP: production quantity multiplied by price gives total revenues; assessed costs enter into cost recovery and influence profit oil and tier reached.
- When R-Factor < 1, minimum share of government profit oil applies. Thereafter two options:
  - (i) scale of discrete tiers; or
  - (ii) band with progressive increasing rates interpolated between minimum and maximum government shares.
- Report favors sliding scale with interpolation to avoid arbitrary tier steps and distortions at crossing points.
- Suggested minimum and maximum government shares: 50 and 75 percent, applying across a band interpolated between an R-Factor of one and then of three.
- Advantages of R-Factor vs DROP:
  - Under DROP, government share follows production profile: increases during first years reaching maximum at peak production then declines.
  - Under R-Factor, government share remains constant until payback point (roughly around peak production) then increases gradually towards maximum as profitability increases.
- Note: maximum government share under DROP is never achieved in absolute terms because DROP operates incrementally; effective government share is weighted average of different shares applying in incremental scale. Example: in previous example highest DROP achieved is 150,000 bbl, corresponding government share is 60.4 percent, below maximum level of 67.5 percent.

### Key numeric figures cited
- Model PSA last issued: 1999.
- ITA provisions for petroleum introduced: 2010.
- Two PSAs signed: 2012.
- 1999 royalty scale tiers and rates:
  - Up to 2,500 (bpd) — 5.0 (In percent)
  - 2,500 up to 5,000 (bpd) — 7.5 (In percent)
  - 5,000 up to 7,500 (bpd) — 10.0 (In percent)
  - Greater than 7,500 (bpd) — 12.5 (In percent)
- Report favors general royalty rate of 8 to 12.5 percent for crude oil.
- Draft model PSA 2015 royalty scale:
  - Up to 25,000 (bpd) — 8 (In percent)
  - 25,000 up to 50,000 (bpd) — 10 (In percent)
  - 50,000 up to 75,000 (bpd) — 12 (In percent)
  - 75,000 up to 100,000 (bpd) — 14 (In percent)
  - 100,000 up to 130,000 (bpd) — 16 (In percent)
  - Greater than 130,000 (bpd) — 18 (In percent)
- PFMA 2015 allocates six percentage points of royalty revenues to local governments.
- Example cost-recovery calculations:
  - 60 percent cost oil limit implies 40 percent of gross production is profit oil; 45 percent of that to government = 18 percent of gross production if no formal royalty.
  - If formal royalty 12.5 percent and cost oil = 60 percent of post-royalty balance: cost oil = 52.5 percent; minimum government share of profit oil = 15.75; total minimum effective royalty = 12.5 + 15.75 = 28.25 percent.
- Recommended shift of cost oil limit to 70 percent in rebalanced model PSA.
- Suggested R-Factor band: minimum and maximum government shares of 50 and 75 percent, across R-Factor 1 to 3.
- Example DROP maximum achieved cited: 150,000 bbl with corresponding government share 60.4 percent compared with maximum level of 67.5 percent.

*Source: cr17367 - 23.*

### 47.      The standard CIT rate for companies at 30 per cent remains appropriate within the

### 47.      The standard CIT rate for companies at 30 per cent remains appropriate within the

### Corporate income tax (CIT) and petroleum companies
- "The standard CIT rate for companies at 30 per cent remains appropriate within the PSA framework proposed."
- Without the production sharing and royalty framework, an additional tax or surcharge approaching the collection of resource rent would be justifiable, but that function is currently performed by the production sharing system.
- Governments should consider whether "the rate of tax on petroleum companies should rise and fall with the general rate or remain at 30 percent unless deliberately changed."

### Example calculation of DROP allocation (numeric breakdown)
- For a DROP of 150,000 bbl:
  - of the first 5,000 bbl the government will receive 45 percent;
  - of the next 5,000 bbl 47.5 percent;
  - of the next 10,000 bbl 52.5 percent;
  - of the next 10,000 bbl 57.5 percent;
  - of the next 10,000 bbl 62.5 percent;
  - anything in excess of 40,000 bbl 67.5 percent.
- "In sum the government receives 90,150 bbl or 60.4 percent of the DROP of 150,000."

### Problems and options in the income tax law for petroleum companies
- "The law on income tax for petroleum companies currently does not work as drafted."
- Decision required: whether to
  - make adjusted profit oil the base for application of the tax rate, or
  - return to aggregating the licensee’s cost and profit oil as gross income and then applying allowable tax deductions to arrive at chargeable income.
- Recommendation preference: "The two-stage calculation with cost and profit oil making up gross income is preferable."
  - Advantage: uniformity and transparency; tax calculation does not depend on how cost oil is calculated in individual PSAs.
  - Allowable deduction rules, including capital allowances, in the ITA need to be uniform and will not always replicate PSA cost recovery rules.

### Reconciliation of PSA cost recovery and ITA allowable deductions
- Administrative desirability: "easy reconciliation between allowable deduction rules for tax and cost recovery rules under PSAs."
- First requirement: standardization of cost recovery rules across PSAs.
- Legitimate reasons for differences:
  - PSA cost recovery follows cash flow principles; ITA rules follow adjusted corporate accounting to tax returns to equity.
  - Interest should be allowable (subject to limits) under the ITA but not recoverable under the PSA.
  - Economic depreciation may be approximated under the ITA but is not necessary under the PSA.
  - The cost oil limit under the PSA is a limit on the rate at which expenditures (“losses”) carried forward are recovered; such a limitation could be imposed under the ITA but not necessarily at the same rate.
- For clarity: keep “recoverable costs” under the PSA and “allowable deductions” under the ITA distinct.

### Recommendations (explicit bullets from the source)
- Set crude oil royalty either at a fixed rate of 8 to 12 percent or by sliding scale of DROP.
- Ensure the provisions of the PFMA on royalty sharing can be implemented simply under the chosen royalty scheme.
- Continue with a cost recovery limit, probably at 70 percent (depending on the royalty scheme chosen).
- Remove financing charges as a cost recoverable item.
- Introduce a 15 percent one-time uplift for development costs during the first five years of development expenditure.
- Adopt the R-Factor scheme for profit petroleum sharing.
- Calculate income tax on petroleum companies from gross income consisting of both cost and profit oil, applying allowable deductions.

### Fiscal modeling of existing and alternative PSA terms
- Modeling framework used: "FAD’s Fiscal Analysis of Resources Industries (FARI) modeling framework."
- Four sets of terms evaluated:
  - PSA EA1A (2012)
  - PSA EA1 (2004)
  - R-Factor Option 1 (alternative)
  - R-Factor Option 2 (alternative)
- Key changes in alternatives:
  - Option 1: flat-rate royalty instead of incremental DROP-based royalty.
  - Option 2: incremental royalty at rates slightly higher than previous PSAs but excluding the additional royalty introduced in 2012.
  - Both options: replace DROP with R-Factor scheme; increase cost recovery limit from 60 to 70 percent; eliminate recoverability of interest expense; offer a one-time limited uplift for development costs.

### Objectives of the alternative terms
- Reduce fiscal burden on marginal projects.
- Make the system more responsive to projects’ profitability.
- Maintain government take close to current PSAs’ levels if parameters are properly calibrated.
- R-Factor ensures government share of profit petroleum increases as project profitability increases, regardless of production rate.

### Stylized project examples and baseline assumptions
- Two stylized oil fields:
  - Large field: total production approximately 956 MM bbl; representative of EA1. Project life 27 years.
  - Medium field: total production 264 MM bbl; representative of EA2. Project life 26 years.
- Price assumption: "US$51/bbl FOB Mombasa, in constant dollars of 2015."
- Project economics (selected entries from Table 4):
  - Large Oil Field:
    - Total production 956 MM bbl; years 27.
    - Exploration costs $MM 1,250; $/bbl 1.3.
    - Development costs $MM 5,400; $/bbl 5.6.
    - Operating costs $MM 7,648; $/bbl 8.0.
    - Pipeline tariff (deduction from FOB price) $MM 11,092; $/bbl 11.6.
    - Decommissioning reporting $MM 550; $/bbl 0.6.
    - Total costs $MM 25,940; $/bbl 27.1.
    - Crude price FOB Mombasa ($/bbl) 51.
    - Pre-tax IRR 18.9%.
  - Medium Oil Field:
    - Total production 264 MM bbl; years 26.
    - Exploration costs $MM 900; $/bbl 3.4.
    - Development costs $MM 2,500; $/bbl 9.5.
    - Operating costs $MM 1,846; $/bbl 7.0.
    - Pipeline tariff (deduction from FOB price) $MM 2,678; $/bbl 11.6.
    - Decommissioning reporting $MM 250; $/bbl 0.9.
    - Total costs $MM 8,174; $/bbl 32.4.
    - Crude price FOB Mombasa ($/bbl) 51.
    - Pre-tax IRR 9.7%.

### Government revenue profiles under the four PSA terms
- Under the large field, "the four sets of fiscal terms modeled yield relatively similar revenue profiles for the government."
- Under the medium field, "the R-Factor options raise less revenue in the early years of the project, but towards the middle they more than offset the differences of the first years."
- In all four PSAs the government starts receiving revenue from day one of production, mainly due to royalties and the combination of a cost recovery limit with a minimum share of profit petroleum.
- The magnitude of early revenues is larger under the 2012 PSA "mainly as a result of the additional royalty."

### Total government revenue at different prices
- "While the 2012 PSAs generate more revenue for the government under current price conditions, as prices increase the revenue generated by the R-Factor alternatives increases faster than the existing PSAs."
- At high prices ("$100/bbl and above"), "the R-Factor options generate higher revenue for the government."

### Revenue generating capacity and Average Effective Tax Rate (AETR)
- AETR defined: ratio of government revenue from a profitable project to the project’s pre-tax net cash flows.
- Undiscounted AETRs:
  - "between 79 and 86 percent" for the large project.
  - "between 79 and 83 percent" for the medium project.
- Discounted AETRs (10 percent discount rate) for the large field:
  - 2004 PSA: 118
  - 2012 PSA: 125
  - R-Factor Option 1: 107
  - R-Factor Option 2: 110
- Explanation: Extremely high discounted AETRs occur because the discount rate used is higher than project post-tax IRR under all four regimes.
- Post-tax IRR under current price conditions:
  - Large field: 9.2 percent.
  - Medium field: 2.5 percent.
- Discount rates used for government and companies: 10 and 12.5 percent respectively.

### Progressivity of fiscal regimes and government share of total benefits
- Progressivity importance: allows government to increase share when investment is highly profitable while giving relief to investors for low returns; serves as proxy for more accurate taxation of economic rent.
- The two alternative sets (R-Factor options) are "more progressive than the existing PSAs," with both options exhibiting identical degrees of progressivity.
- Main driver of higher progressivity: switch from DROP to R-Factor mechanism.
- Difference between option 1 and 2 is minimal; only royalty structure differs (flat relatively low rate vs. incremental rate).
- Caution: increased progressivity may reduce government take on the downside unless a sufficient minimum government revenue exists whenever production occurs.

### Breakeven price and marginal project burden
- Breakeven price defined as minimum price required to meet the investor's minimum rate of return (assumed in model to be 12.5 percent real).
- Large field:
  - "The 2012 and 2004 PSAs place a higher burden on marginal projects than the R-Factor options."
  - R-Factor, especially with flat royalty, reduces the breakeven price.
- Medium field:
  - Results reverse: "R-Factor can produce a higher breakeven price than the DROP mechanism in fields with lower rates of production."
  - Reasons:
    - In early years of smaller fields, government share of profit petroleum under DROP (first two tiers 45 and 47.5 percent) is on average lower than the minimum government of 50 percent in the R-Factor.
    - By the time project reaches post-tax IRR of 12.5 percent, the R-Factor may already be higher than 1, triggering higher government shares.
  - Net result: "a higher breakeven price for the R-Factor than the DROP mechanism in fields with lower rates of production."
- Note: under both projects all PSAs evaluated require a higher breakeven price than the one assumed for the rest of the analysis.

*Source: IMF staff report (excerpts as provided in the supplied content).*

### 63.      The report illustrates sensitivity analysis on the fiscal parameters contained in the

### cr17367 - 63.      The report illustrates sensitivity analysis on the fiscal parameters contained in the

### Sensitivity analysis — price scenarios and key drivers
- Two oil price scenarios analyzed:
  - $51/bbl (price used throughout most of the analysis in this section)
  - $80/bbl (higher-price scenario to reflect production starting several years after 2015)
- Under the $51/bbl scenario:
  - Changes to the minimum government share of profit petroleum have the greatest effect on government revenue and post-tax IRR.
  - Decreasing the minimum government share from 50 to 40 percent:
    - Government NPV10 falls by 4 percent, or $147 million.
    - Post-tax IRR increases from 8.2 to 8.9 percent.
  - Increasing the minimum government share from 50 to 60 percent:
    - Government revenue increases by $163 million, or 5 percent.
    - Post-tax IRR falls to 7.3 percent.
- Under the $80/bbl scenario:
  - Changes to the maximum government share of profit petroleum have the greatest effect on government revenue and post-tax IRR.
  - A 10 point increase in the maximum government share:
    - Increases government revenue by $268 million.
    - Reduces post-tax IRR from 14.6 to 13.8 percent.
  - A 10 percent decrease in the maximum government share:
    - Reduces government revenue by $230 million.
    - Increases post-tax IRR to 15.4 percent.
- Additional sensitivity outputs are summarized in Figure 7 (government revenue and post-tax IRR results at $51/bbl and $80/bbl).

### Expected Monetary Value (EMV) analysis and “implied” bid bonus
- EMV methodology:
  - Expected NPV per dollar of exploration expenditure = (probability of unsuccessful exploration × expected NPV loss from failed exploration costs) + (probability of successful discovery × expected after-tax positive NPV from the project).
- Exploration success assumption used in report:
  - Probability of discovery: 85 percent (report notes probability of large commercial discoveries will in practice be lower).
  - Company discount rate: 12.5%
  - Oil price used in EMV example: $80/bbl
- EMV and “implied” bid bonus results:
  - Large oil field (R-factor Option 1):
    - NPV of exploration failure: -1,209
    - NPV of successful discovery: 492
    - EMV (implied bid bonus): 236
  - Large oil field (R-factor Option 2):
    - NPV of exploration failure: -1,209
    - NPV of successful discovery: 409
    - EMV (implied bid bonus): 166
  - Medium oil field results (same assumptions):
    - R-factor Option 1:
      - NPV of exploration failure: -880
      - NPV of successful discovery: -387
      - EMV (implied bid bonus): -461
    - R-factor Option 2:
      - NPV of exploration failure: -880
      - NPV of successful discovery: -394
      - EMV (implied bid bonus): -467
- Interpretation:
  - For the large field, companies may be willing to offer bid bonuses of $236 million (Option 1) and $166 million (Option 2).
  - For the medium field, EMV is negative because the assumed price of $80/bbl is lower than the minimum price required by investors.

### International comparisons (AETR, progressivity, breakeven prices)
- Comparator countries include: Chad, Sudan, DRC, Mozambique, Tanzania, Kenya, Australia, Colombia.
- AETR results:
  - The 2012 and 2004 PSA fall in the higher end of the sample under the AETR (similar to Tanzania Model PSA 2013 and Sudan Model EPSA 2011).
  - R-Factor options are in the mid part of the range, slightly higher government take than Kenya’s newly introduced model PSC.
- Progressivity:
  - R-Factor options are relatively more progressive than many countries in the sample.
  - 2012 and 2004 PSAs are similar to other countries in the region and elsewhere.
  - Australia and Colombia exhibit relatively progressive regimes (use of rent-capturing mechanisms and absence of very high minimum effective royalties noted).
- Breakeven price comparisons (large and medium fields):
  - Range is broad; examples:
    - Tanzania investors require $100/bbl and $162/bbl to breakeven in the large and medium field respectively.
    - Australia investor requires $47/bbl and $76/bbl to breakeven in the large and medium field respectively.
- Summary of impact on investor returns and risk:
  - Current fiscal terms in Uganda produce low mean expected post-tax returns and higher volatility relative to many comparators.
  - R-Factor options improve outcomes: increase mean expected after-tax IRR from 8.1 to 11.2 percent in the large field and reduce tax-induced probability of below-target returns from 72 to 54 percent.

### Implied risk premium and simulated price analysis
- Price simulation approach:
  - Prices generated using a simple autoregressive model replicating past oil price behavior.
  - Bounds imposed: lower $20/bbl, upper $200/bbl.
  - Exercise repeated hundreds of times to build distribution of possible future prices.
- Report evaluates:
  - Expected average post-tax IRR
  - Variation in post-tax returns (coefficient of variation)
  - Probability of tax-induced negative returns for the investor over simulated price range
- Key comparative findings (large field, selected figures shown in report):
  - Pre-tax project IRR examples:
    - Project EA1 field: Pre-tax IRR 19% (size: 956 MMBbl; Costs: $27.1 BOE; discount rate: 10.0%)
    - Project EA2 field: Pre-tax IRR 13% (size: 265 MMBbl; Costs: $32.4 BOE; discount rate: 10.0%)
  - Post-tax IRR and tax-induced probability of below-target returns (large oil field, excerpted ordering):
    - Tanzania: 6.4778 mean post-tax IRR, coefficient of variation 2, tax-induced probability (below 12.5%) 82
    - Uganda: Block EA1 (2012): 8.1767 mean, tax-induced probability 72
    - Uganda: R-factor Option 1: 11.253 mean, tax-induced probability 54
    - Uganda: R-factor Option 2: 10.656 mean, tax-induced probability 56
    - Australia: PRRT: 17.838 mean, tax-induced probability 12

### State participation, PFMA, and public finance implications
- Modeled state carried interest:
  - Assumed at 15 percent in each scenario (election after commercial discovery and prior to issue of a PL).
  - State (or NATOIL) does not reimburse proportionate exploration expenditure and is “carried” through initial development by private contractors.
  - Government reimburses its share of development costs from its share of oil produced, with interest at LIBOR, and without recourse to other state assets.
- Alternatives and implications:
  - Different participation percentages and repayment terms change contingent liabilities and present value cost to private contractors.
  - If carry is repaid only out of government share of cost oil, repayment is slower and cost in present value to private contractors is greater.
  - Need clarity on treatment of state participation after recovery of initial development expenditure (whether carry continues or government must meet subsequent cash calls).
  - Joint operating agreement must address delayed or missed cash calls and possible dilution of government participation.
- PFMA 2015 provisions and issues:
  - PFMA received Presidential assent on February 23, 2015.
  - “Petroleum revenue” (PFMA s3) definition includes: “tax paid under the Income Tax Act on income derived from petroleum operations, government share of production, signature bonus, surface rentals, royalties, proceeds from the sale of government share of production, any dividends due to government, proceeds from the sale of Government’s commercial interests, and any other duties or fees payable to the Government from contract revenues under a petroleum agreement.”
  - Petroleum revenue collection and flows:
    - Collected by Uganda Revenue Authority (URA), transferred to the Petroleum Fund, then to the Consolidated Fund or the Petroleum Investment Reserve.
- Legal and operational clarifications needed:
  - The definition of petroleum revenues appears to exclude cost oil due to government; if cost oil is included, carried interest arrangements cannot work as intended and government contributions to costs will require budget votes.
  - Bonuses other than signature bonuses are excluded from the definition; PEDPA 2013 also excludes these from sources of funds for the Petroleum Authority of Uganda — these inconsistencies require clarification.
  - Reference to dividends affects NATOIL operations: definition provides that NATOIL returns dividends and its own tax payments to the government (rather than gross proceeds), requiring rules on NATOIL’s dividend policies, retention of profits, and investment programs.

### Explicit recommendations (as listed in the report)
- Continue with carried interest for state participation at a maximum rate fixed in the Model PSA.
- Clarify the obligations of the government (or its nominee) after recovery of initial capital investment.
- Align the definitions of petroleum revenues in the PFMA, PEDPA, and model PSA for consistency.
- Develop rules for NATOIL’s policies on investments, profit retention, and dividends.

### Project configuration and background (summary)
- Project components:
  - Upstream production from four contract areas
  - Early petroleum production for power generation
  - A refinery in Uganda
  - A crude oil export pipeline
- Publicly reported project scale and arrangements:
  - Anticipated recoverable reserves about 1.2 to 1.7 billion bbl across upstream
  - Early petroleum production for power likely from Kingfisher discovery area (PL issued)
  - Refinery separate from upstream JV; initial priority for 30,000 bpd of crude rising to 60,000 bpd as capacity expands
  - Crude oil export pipeline to be sponsored by upstream JV partners (likely government participation); pipeline route not selected but expected to pass through Kenya with a spur for Kenyan oil from Turkana region
  - Preferred bidder announced by MEMD in February 2015 for construction of the refinery; negotiations on contract proceeding

*Source: cr17367 - 63.      The report illustrates sensitivity analysis on the fiscal parameters contained in the*

### 82.      The project requires a series of linked activities, decisions, or preconditions in order

### 82.      The project requires a series of linked activities, decisions, or preconditions in order

### Project sequencing, preconditions, and current status
- PSA contractors forming the JV have not yet commenced FEED, essential before a FID, because other preconditions are not in place.
- Upstream discovery areas each require approval of development plans and grant of PLs; only the PL for Kingfisher was issued at the time of the mission.
- Consideration of the other development plans has been in process for more than one year.
- The extent to which the contractors have explored financing options is not known.
- Grant of PLs (giving the right to develop and produce) is essential, but would probably have to be simultaneous with, or effectiveness contingent upon at least the following:
  - (i) settlement of an intergovernmental agreement (IGA) on terms and conditions for the export pipeline between Uganda and Kenya;
  - (ii) settlement of counterpart host government agreements (HGA) on the pipeline between the JV partners, and the two governments and/or the grant of licenses (with suitable terms and conditions) for pipeline construction and operation under the relevant legislation;
  - (iii) a commitment by the relevant investors and the government to refinery construction and offtake arrangements, if the project is to commence with the obligation to supply 30,000 bpd for domestic refining increasing to 60,000 bpd as capacity refinery expands.
- It was understood by the mission that in principle either the pipeline or the refinery could proceed independently.

### Tax issues affecting timing of project decisions
- VAT application currently operates potentially to increase exploration costs; the issue needs a solution for the project and the new licensing round.
- ITA issues concern withholding tax on technical services provided by non-residents, and the working of the schedules of the ITA applicable to petroleum companies.
- These VAT and ITA issues are addressed elsewhere in the report.

### Upstream oil pricing: delivery point and valuation
- Crude oil is valued for production sharing at the “delivery point” from the field facilities.
- In the PEDPA 2013 (s2) the delivery point means “the point at which petroleum passes through the intake valve of the pipeline, vessel, vehicle or craft at a terminal or refinery in Uganda.”
- The PSAs provide for “such other point, which may be agreed in writing by the Parties.” The PEDPA post-dates the PSA and is presumed to prevail.
- For present purposes, the report assumes:
  - crude oil supplied to a refinery will be valued at the inlet of that refinery;
  - crude oil exported by pipeline will be valued at the main inlet flange of that facility.
- Costs incurred in moving petroleum from field wellheads to these delivery points will form part of the upstream accounts.

### Netback pricing and pipeline tariff determination
- A netback from the FOB price at the port of export will determine the value of crude oil exported by pipeline. “Netback” means the value of the oil after deduction of the transportation tariff levied by the pipeline company.
- Two illustrated tariff calculation approaches (Box 2):
  - tariff by reference to equity contributions of the pipeline owners; or
  - tariff by reference to total cost of the pipeline and its expected throughput life.
- All mechanisms require definition of an allowed rate-of-return; alternatives include return-on-asset regulation or an annuity/discounted cash flow approach.
- The report models pipeline tariff sufficient to recover capital and operating costs and yield a real post-tax rate of return of 7.5 percent (for simulations only).

### Economics and operation of petroleum pipelines (cross-border considerations)
- Cross-border pipelines pose more complex legal, regulatory and fiscal issues than domestic lines; different national laws apply and international law is limited in this domain.
- A cross-border pipeline is generally governed by an IGA among the countries concerned, ratified as a treaty, supplemented by agreements including HGAs and transportation agreements that set tariffs.
- Negotiating the series of agreements and financing structures for cross-border pipelines typically takes considerably longer than the construction itself.
- Pipelines have high capital costs but low operating costs; economies of scale minimize unit tariffs (in US$/bbl).
- Countries generally prefer fewer larger pipelines with “third party access” (TPA) provisions to maximize upstream revenues by minimizing transportation tariffs.
- Two main alternatives for TPA tariffs:
  - regulated tariffs (commonly used in OECD countries); or
  - commercial tariffs negotiated on the principle of “fair and reasonable tariffs,” often including an equity-related formula.

### Implications for pricing, capital structure, and long-term access
- The pipeline tariff, once determined, sets a yardstick for the pricing of oil produced in Uganda (“export parity price”) and forms the benchmark for pricing crude oil entering the proposed refinery.
- The refinery appears capable of profitably sustaining this input price provided products are priced at or near import parity levels.
- Project capital participants will include:
  - equity holders: upstream JV partners for the pipeline company, and an independent venture for the refinery;
  - third party lenders, since upstream and midstream facilities are likely to be substantially debt financed.
- The Ugandan government expects a 15 percent fully paid equity interest in the pipeline company; the government would expect to participate as a joint venture participant or equity partner throughout the chain. The Kenyan government may intend the same for facilities within its territory.
- Project structure must specify allocation of transportation revenues and costs across countries, mirrored in taxing rights.
- Exclusive rights to transport infrastructure should be limited; third-party access is vital in the long term. There may be a need for a period of exclusivity to attract initial investment.
- The EAC countries do not intend to impose transit fees for intra-Community pipelines; third party access rights are usually more important than transit fees.

### Recommendations (pricing and access)
- Confirm the definition of delivery point for valuation of crude oil.
- Determine the pipeline tariff formula to govern netback pricing of crude oil at the delivery point.
- Confirm the pricing schemes for input of crude oil to the refinery and the output of petroleum products.
- Limit exclusive rights to capacity in transportation infrastructure to the minimum necessary to induce initial investment.

### Income taxation of midstream facilities
- The pipeline company is usually subject to the tax regime applied to pipeline activities in each country; a common fiscal regime across countries is not usually selected.
- With separate regimes, the pipeline company must prepare and submit accounts and tax returns separately for each country’s tax authorities.
- Rules should be jointly defined and agreed among transit countries to allocate revenues and costs of the transit pipeline project fairly between the two countries; each country then applies its tax system.
- The pipeline must satisfy permanent establishment rules in each country.
- Under current law:
  - income tax treatment of refineries and pipelines is straightforward; these businesses would be taxed under general income tax rules;
  - in international pipelines, the pipeline owner would be subject to regular profit tax on the share of the pipeline’s income attributable to each country.
- Allocation of costs and revenues for tax purposes can follow relative length of each segment or other relevant criteria (e.g., location of capital cost incurred); allocation rules should be set out in the pipeline agreement and IGA.
- Depreciation rates (Sixth Schedule of the Income Tax Act):
  - refinery plant and equipment: 30 percent declining balance (refinery operation is manufacturing);
  - pipeline: 20 percent declining balance (pipeline is “a depreciable asset not included in another class”).
- Kenya’s depreciation rate for a pipeline is 12.5 percent declining balance.
- Policy on tax holidays:
  - A pipeline or a refinery investment should not be granted a tax holiday; government loses net revenue when tax relief is given to midstream facilities.
  - Pipeline or refinery will only be constructed if producers agree to ship sufficient oil to ensure recovery of costs and an adequate return.

### Recommendations (taxation)
- Confirm that a cross border pipeline and associated facilities in the territory of Uganda are subject to the domestic tax regime of Uganda.
- Determine, with Partner States, the inter-state allocation principles for costs and revenues of a cross-border pipeline and associated infrastructure.
- Ensure that, within Uganda, the pipeline and refinery are subject to standard ITA rules, without special tax reliefs or exemptions.

### Fiscal modeling: scope, assumptions, and key project parameters
- The report models the upstream segment, the pipeline, and the refinery projects over their proposed life.
- Project components:
  - (i) an upstream segment, developed as one integrated project by Tullow, Total and CNOOC;
  - (ii) a pipeline to export crude oil via Mombasa; and
  - (iii) a refinery to supply finished products to the local market and other countries in the region.
- Upstream segment is subject to the respective PSAs; pipeline and refinery are assumed to be subject to normal business taxation and developed as separate, independent entities.
- Upstream production assumptions:
  - crude production mainly from areas EA1 (6 discoveries), EA2 north and south (four discoveries each), and EA3A (one discovery);
  - total estimated production is in excess of 1.3 billion bbl;
  - production gas 33 MMBOE;
  - production BOE 1,376 MMBOE;
  - production years 27.
- Processing plants planned:
  - largest plant serving EA1 and EA2 north with capacity to handle 190,000 bpd;
  - processing plants with capacities of approximately 15,000 bpd (EA2 south) and 40,000 bpd (EA3A).
- The report assumes terms of the three PSAs are the same as terms for EA1 modeled in s II of the report.
- Upstream project cost and unit statistics (Constant 2015 US$):
  - Exploration costs 2,850 $ million, 2.1 $/Bbl
  - Development/capital costs 9,800 $ million, 7.1 $/Bbl
  - Operating costs 9,994 $ million, 7.3 $/Bbl
  - Tariff pipeline costs (outside PSA) 15,601 $ million, 11.6 $/Bbl
  - Decommissioning 1,000 $ million, 0.7 $/Bbl
  - Total 39,245 $ million, 28.5 $/Bbl

### Pipeline and refinery project assumptions and key parameters
- Pipeline assumptions:
  - crude export pipeline capacity: 210,000 bpd;
  - approximate pipeline length: 1,400 km, of which approximately 40 percent would lie in Ugandan soil;
  - pipeline required to be heated given physical characteristics of the Ugandan crude;
  - government would take up a 15 percent fully paid equity interest in the pipeline company;
  - pipeline company assumed to charge a tariff sufficient to recover capital and operating costs and yield real post-tax rate of return of 7.5 percent (simulation assumption).
- Refinery assumptions:
  - operated on an export parity basis to purchase crude and on an import parity basis to sell refined products (assumption for modeling and subject to further review);
  - modeled initial capacity to process 30,000 bpd, increasing to 60,000 bpd after seven years;
  - production slightly under 3,000 kt/year of finished products (including gasoline, diesel, fuel oil, jet kerosene, and liquefied petroleum gas);
  - government would take a 40 percent fully paid equity interest in the refinery.

_Italic line: Source: cr17367 - 82.      The project requires a series of linked activities, decisions, or preconditions in order_

### 102.      Since the project is expected to commence production and operations in 2019,

### cr17367 - 102.      Since the project is expected to commence production and operations in 2019,

### Price assumption and implications
- Price used for analysis: $80/bbl FOB Mombasa.
- Rationale: project expected to commence production and operations in 2019; price assumption affects upstream results and refinery output prices because import parity is assumed.
- Pipeline results: independent of prices because tariff depends on project cost and assumed throughput.
- Note on product price calculation: starts with the FOB Arab Gulf price for each product, then adds transportation costs to Mombasa, and then inland transportation costs to arrive at a price in Uganda.

### Project financial and operational summary
- Total project pre-tax net cash flow (NCF) over entire life: almost $98 billion.
- Total project pre-tax IRR: 23.4 percent.
- Revenue composition: largest share from upstream, followed by refinery and pipeline.
- Refinery as component: pre-tax IRR of 30 percent (higher profitability due to assumption of selling products at import parity prices).
- Caution: import parity assumption for refinery requires careful future review.

Pipeline (Uganda portion) — key figures
- Pipeline Capacity daily: 210 Mbopd
- Maximum crude oil throughput (daily): 210 Mbopd
- Total crude oil throughput: 872 MMBOE
- Operation years: 21
- Constant 2015 dollars: Capital costs $ million 3,621; $/Bbl 4.2
- Constant 2015 dollars: Operating costs $ million 1,728; $/Bbl 2.0
- Total $ million 5,349; $/Bbl 6.1

Refinery — key figures
- Capacity daily - initial rising to 60 Mbopd
- Maximum crude oil processed (daily): 60 Mbopd
- Total crude oil processed: 471 MMBOE
- Operation years: 27
- Constant 2015 dollars: Capital costs $ million 2,268; $/Bbl 4.8
- Constant 2015 dollars: Operating costs $ million 1,212; $/Bbl 2.6
- Cost of crude oil processed $ million 32,218; $/Bbl 68.4
- Total $ million 35,698; $/Bbl 75.8

Aggregate financial metrics (NPV and rates at different discount rates)
- Total upstream:
  - Project pre-tax NCF: 70,419 (0%); 12,726 (10%); 8,204 (12.5%)
  - Government revenue: 55,720 (0%); 12,290 (10%); 8,909 (12.5%)
  - AETR: 79% (0%); 97% (10%); 109% (12.5%)
  - Pre-tax IRR: 23.3%
  - Post-tax IRR: 11.4%
- Pipeline (Uganda portion only):
  - Project pre-tax NCF: 1,907 (0%); -1 (10%); -138 (12.5%)
  - Government revenue: 642 (0%); 71 (10%); 30 (12.5%)
  - AETR: 34% (0%); -6292% (10%); -22% (12.5%)
- Refinery:
  - Project pre-tax NCF: 25,728 (0%); 4,401 (10%); 3,570 (12.5%)
  - Government revenue: 15,301 (0%); 2,421 (10%); 1,611 (12.5%)
  - AETR: 59% (0%); 55% (10%); 45% (12.5%)
  - Pre-tax IRR: 29.9%
  - Post-tax IRR: 26.0%
- Total project:
  - Project pre-tax NCF: 98,053 (0%); 16,725 (10%); 10,689 (12.5%)
  - Government revenue: 71,663 (0%); 14,781 (10%); 10,550 (12.5%)
  - AETR: 73% (0%); 88% (10%); 99% (12.5%)
  - Pre-tax IRR: 23.4%
  - Post-tax IRR: 13.7% (0%); 10.0% (10%); 7.5% (12.5%)

### Government revenue projections and sensitivity
- Government revenue estimated in excess of $60-70 billion over 27 years.
- Revenue sources: mostly upstream (subject to PSAs), then refinery (government assumed 40 percent stake).
- Sensitivity analysis highlights:
  - Price changes have the largest effect on government revenues, then production changes.
  - A reduction in the price used for the analysis of $20/bbl reduces government revenue by more than 35 percent in NPV terms (discount 10%).
  - A 20 percent reduction in total production decreases government revenue by about 25 percent.
  - For project returns, price and production changes have the largest impact on post-tax IRR; capital cost changes can also materially affect post-tax results.
- Representative Government Revenue NPV10 figures (illustrative from sensitivity chart):
  - Various scenarios produce Government Revenue NPV10 values including 9,668; 11,182; 15,164; 15,662; 20,090; 18,492; 14,403; 13,961 (values shown in sensitivity figure).
- Project Post-Tax IRR sensitivity (illustrative percentages from chart):
  - Changes in oil price, production, capex, opex yield Post-Tax IRR values including 9.5%, 10.3%, 10.5%, 11.5%, 12.5%, 13.4%, 14.0%, 15.4%, 16.3%, 16.4% (values shown in sensitivity figure).

### Mining and minerals fiscal regime — sector legislation
- Primary law: Mining Act of 2003.
- Licenses: prospecting license (non-exclusive), exploration license, retention license, mining lease, location license (small scale exploration and mining).
- Priority: for a mineral right other than a prospecting license, priority is first-come, first-served (section 6 of the regulations). Holder of an exploration license has priority for grant of a mining lease on that land (section 42).
- Exclusivity and durations:
  - Exploration licenses: up to 3 years with two 2-year extensions (maximum 7 years).
  - Mining leases for development and production: initial period of 21 years or the estimated life of the ore body, whichever is shorter; one renewal up to 15 years or the estimated life of the ore body.
- Other provisions:
  - Act imposes a royalty and empowers the Minister to make mineral agreements (s 18).
  - Agreements may determine market value basis but cannot override statutory requirements.
  - Current examples: concession to restart Kilembe copper-cobalt mine; mineral development agreement for Sukulu phosphate and steel project (phosphate agreement modifies tax obligations; government to amend legislation to regularize agreement).
  - Act contains no provision for bidding of licenses, state participation, or fiscal stability.
  - Prospecting licenses cannot be transferred; other mineral rights transferable with Commissioner approval. Transfer provisions do not cover indirect transfers (e.g., transfer of control).

### Mining fiscal regime — royalties
- Royalty structure:
  - For high-value minerals assessed on gross value based on prevailing market price.
  - Rates (increased in 2011): 5 percent for precious metals and base metals; 10 percent for precious stones (Third Schedule of the Regulations).
  - Other minerals (including coal): specific rates based on weight (e.g., UGX 10,000 per ton for phosphate).
- Revenue performance (2013):
  - Mining companies paid UGX 59 billion (about $21 million) in income and withholding taxes (other than on employees); withholding payments were 63 percent of the total.
  - UGX 4.9 billion (about $1.7 million) in non-tax revenue in 2013, of which royalty payments were 68 percent of the total.
- Strengths and concerns:
  - Strengths: royalties secure early revenue, easier administration, ensure minimum payment, function as an implicit depletion policy.
  - Risks: high royalties may discourage marginal deposits, lead to high grading and early mine closure.
  - Ambiguity: Regulations deem market price to be London Metal Exchange or other market as known to the Commissioner, but it is unclear whether value refers to ore at mine mouth, first product sold/exported, or recoverable minerals.
  - Regulations specify net smelter return for minerals exported to a refinery approved by the Commissioner; assumed fineness specified for gold (95 percent) and tin (75 percent).
  - Commissioner has considerable discretion in determining valuable contents of other minerals.
- Recommendations for royalty regime:
  - Define gross value for royalty purposes as gross revenues from the first sale or FOB export value if exported without sale, or net smelter return if sent to a smelter or refinery.
  - Require mineral companies to self-assess the royalty and make monthly payments (with Commissioner auditing returns).
- Additional features:
  - Export permit for minerals can be issued only if royalty due has been paid or secured.
  - Ministerial discretion (with Cabinet approval) to waive royalty if expedient in the interest of production.
  - Deficiencies to address: power to adjust prices for related-party sales where no reference price is available; move from Commissioner assessment with 30-day payment delay to self-assessment with monthly payments.

### Mining fiscal regime — income tax
- Mining-specific income tax features:
  - Corporate income tax for a company carrying on mining operations: sliding scale with minimum rate of 25 percent and maximum rate of 45 percent (Part II of the Third Schedule of the ITA).
  - Non-mining corporate tax rate: 30 percent.
  - Sliding scale formula: 70 – 1500/X, where X is the ratio of chargeable income to gross revenue (includes net gain from disposal of business assets used in mining operations but not any net loss) expressed as a percentage point.
  - Under formula: variable rate is 25 percent if profitability ratio is 33.3 percent or lower; 45 percent if profitability ratio is 50 percent or higher.
- Features and gaps:
  - Variable rate designed to lower tax in years of poor relative profitability and raise it in high-profitability years.
  - Mining income tax provisions are scattered across the Act; no provisions for mine reclamation and closure expenditure, ring fencing, or fiscal stability.
  - Variable rate requires ring fencing mining income from other company income.
- Observations on international practice:
  - South Africa variable rate for gold mines was adapted in Namibia; Botswana introduced variable income tax in 1998; Zambia in 2008.
  - Compared to Uganda, Zambia’s variable rate is more progressive when profitability ratio is low; Botswana’s formula similar to Uganda’s but has no maximum rate and minimum rate is 30 percent.
- Policy note:
  - Variable rate advantages: simplicity, potential to produce revenue in early years if profitability ratio is high, may encourage mining of low-grade ores, and can reduce investor-perceived risk.
  - Other rent tax devices could be considered.

*Source: cr17367 - 102.      Since the project is expected to commence production and operations in 2019,*

### Box 3. Two Leading Forms of Rent Tax

### Box 3. Two Leading Forms of Rent Tax

### 1. The ‘Brown Tax’ (R-based cash flow tax)
- Base: all current receipts less all current expenses (both non-financial), with immediate refund (or carryforward at interest) when this is negative.
- Key features: accounting and tax depreciation do not feature—all capital is immediately expensed—and there are no deductions for interest or other financial costs.
- Two main variants:
  - Resource rent tax:
    - Replicates many features of the Brown Tax, with the investor receiving an annual uplift on accumulated losses until these are recovered.
    - As originally designed by Garnaut and Clunies Ross (1975), the uplift rate is set at the minimum required rate of return for the investor; this choice is now widely questioned.
    - Australia uses this scheme for both mining and petroleum, while Angola’s production-sharing scheme uses the mechanism.
    - It is usually applied with ring-fencing by license.
  - Tax surcharge on cash flow:
    - Adjust accounting profit by adding back depreciation and interest, and deduct any capital expenditure in full to yield a base of net cash flow; this base could form the base for a surcharge.
    - Instead of permitting an annual uplift for losses carried forward, a simple uplift (investment allowance) could be added to capital costs at the start—this is done in the United Kingdom by a time-limited uplift on losses.
    - In the UK, this surcharge is combined with conventional CIT, within the same sector-wide ring fence.
    - Variants include the “R-factor” or payback ratio scale used in some PSCs, and the “investment credit” of Indonesian PSCs.

### 2. Allowance for Corporate Equity (ACE) or Allowance for Corporate Capital (ACC) schemes
- ACE:
  - Amends the standard CIT by providing a deduction for an imputed return on book equity.
  - Tax depreciation remains, but becomes irrelevant because faster depreciation reduces equity and hence future deductions by an offsetting amount.
- ACC:
  - Also gives the interest deduction at a notional rate, eliminating any distinction between debt and equity finance.
- Examples and proposals:
  - Norway’s special petroleum tax approximates the ACC, though its combination of uplift on total investment and limitation on interest deduction differs from a “pure” ACC. It also offers refund of the tax value of exploration losses and of ultimate losses on licenses.
  - In 2010, the Henry Report proposed for Australia “a uniform resource rent tax...[using] an allowance for corporate capital system” (Henry Proposal).
  - Several countries (Belgium, Brazil, Italy, and others) apply ACE-type schemes as their main corporate tax.

### Timing difference between Brown Tax and ACE/ACC
- Central difference: timing of tax payments.
  - Under the Brown Tax: tax is payable only at the perhaps distant date in which costs have been fully recovered.
  - Under the ACE/ACC: tax is payable as soon, roughly speaking, as annual income covers the annual cost of financial capital.
- Implication: ACE/ACC generally yields earlier tax payments than Brown Tax.

### Recommendation and technical correction (from later discussion)
- If the variable rate tax is retained (as the report recommends), one technical correction should be made:
  - Define the profitability ratio as the ratio of chargeable income before any net interest expense to gross revenue.
  - The variable rate would continue to apply to chargeable income from mining operations.
- Explicit recommendation:
  - Retain the variable income tax rate and define the profitability ratio as the ratio of chargeable income before any net interest expense to gross revenue.

*Box 3. Two Leading Forms of Rent Tax — IMF Country Report (excerpt).*

### 139.      While the 2010 amendments included the detailed rules on deductible expenditures

### cr17367 - 139.      While the 2010 amendments included the detailed rules on deductible expenditures

### Corporate tax base for petroleum contractors
- The 2010 amendments included detailed rules on deductible expenditures, but these rules "would appear to have no actual operation."
- Statutory cross-references cited:
  - S 89F refers to the expenditures deductible in ascertaining the chargeable income of a contractor in relation to petroleum operations.
  - S 89E refers to an amount “allowed as a deduction”.
  - S 89B(4) provides that a contractor is not taxed on chargeable income but is taxed on their share of profit oil.
- Under the relevant PSA:
  - Profit oil = total value of production reduced by cost oil.
  - Profit oil is split between the government and the contractor based on the PSA formula.
  - Therefore, the contractor’s recoverable costs under the PSA (not the Part IXA and Eighth Schedule allowable deductions) effectively determine the contractor’s tax outcome.
- Implications:
  - There will be a significant degree of commonality between recoverable costs and deductible expenditures in the Eighth Schedule, but "there will be some important differences."
  - In particular, the cost limit and expensing of capital expenditure for cost recovery purposes will apply also for the purposes of the corporate tax.
- Options discussed:
  - Reframe the corporate tax base if the “profit oil as tax base” approach is retained: define chargeable income of a contractor, in relation to petroleum operations for a year of income, as the contractor’s profit oil under the PSA subject to adjustments (e.g., add-back of new development expenditure and a corresponding deduction for depreciation of such expenditure).
  - Preferable alternative: revert to the pre-2010 approach — calculate chargeable income of a contractor under the normal rules in the ITA subject to any special rules for petroleum operations so the corporate tax base is the same for all contractors.

### Ring-fencing
- S 89C (ring-fencing rule) appears to have no operation for contractors because it refers to amounts that may be “deducted” under the Act, and chargeable income is not the corporate tax base for contractors in petroleum operations.
- Ring-fencing under the relevant PSA will apply instead.
- For mining and petroleum, recommended approach: ring-fence by reference to license areas granted, with exceptions for failed exploration on relinquished areas and for technically warranted joint development or adjacent mines.

### Exploration and development expenditure
- General principles:
  - Exploration expenditure is high-risk and often expensed as an incentive.
  - Development expenditure is incurred after discovery and should be amortized over the life of the project, with possible acceleration.
  - The ITA should cross-refer to sector legislation to distinguish exploration and development phases.
- Current statutory provisions and gaps:
  - Expensing of exploration expenditure:
    - Mining: s 36.
    - Petroleum: s 89F and the Eighth Schedule.
    - Effect: expensing creates losses carried forward until production revenues arise.
  - Definition ambiguity:
    - The definition of exploration expenditure should include the cost of acquiring the relevant exploration right; current law is unclear. Absent such a rule, cost of the exploration right is an intangible asset amortized under s 31.
  - Deduction for depreciable assets used in exploration: should be limited to depreciable assets whose first use is in exploration activities.
  - Harmonization recommendation: same rules for exploration expenditure should apply to both mining and petroleum; include a simplified version of the Eighth Schedule exploration rules in Part IXA.
- Development expenditure treatment differences:
  - Mining:
    - No specific provisions for development expenditure; general ITA rules apply.
    - Intangible development costs: amortized under s 39; useful life dependent on asset, possibly the life of the project.
    - Possible absence of deduction for capital mining development expenditure that does not give rise to an intangible asset.
  - Petroleum:
    - S 89F and paragraph 7(2) of the Eighth Schedule: amortization of development expenditure over the lesser of (i) the life of the petroleum operations as specified in the petroleum agreement; or (ii) six years.
  - Depreciable assets:
    - Mining: normal ITA rules; industrial buildings depreciated 5 percent a year straight-line; plant and equipment used in mining depreciated 30 percent a year using declining balance and pooled accounts (Sixth Schedule).
    - Historical allowances: prior to the 2014 amendments industrial buildings allowed a 20 percent initial allowance, and plant and equipment (other than transport vehicles) allowed a 75 percent initial allowance.
    - Petroleum: appears to depreciate depreciable assets over the lesser of (i) life of petroleum operations as specified in the petroleum agreement; or (ii) six years.
    - Recommendation: align depreciation of depreciable assets for mining and petroleum; the mining depreciation rule is appropriate.
  - Timing of deductions:
    - Petroleum: paragraph 7(3) of the Eighth Schedule — deductions for petroleum development expenditure (including depreciable assets) commence in the year commercial production commences.
    - Mining: no similar limitation; recommended that same rule apply for mining development expenditure to avoid excessive carryforward losses in early development years.
  - Recommendation: adopt common rules for mining and petroleum development expenditure (including depreciable assets) and include these rules in the body of Part IXA.

### Decommissioning, mine closure and rehabilitation costs
- Recommendations:
  - Mine rehabilitation and mine closure costs should be prefunded or at least guaranteed.
  - Preferred approach: allow current tax deduction for payments to an interest-bearing escrow account under joint control of the government and the company; surplus on closure returned to the company and taxed.
  - If escrow approach adopted, amend the Mining Act to require prefunding through an escrow account under joint control.
  - Alternative approach: allow tax-deductible provisioning for future costs (deduction for increases in the provision) but require acceptable security for environmental obligations; guarantee would disappear on transfer of interest.
  - The report recommends the escrow/prefunding approach as less risky.
- Petroleum-specific:
  - PEDPA requires establishment of a decommissioning fund for each development area (s 113).
  - ITA envisages petroleum projects will establish a decommissioning cost reserve and only allows a deduction for the amount the contractor carries to the decommissioning cost reserve (s 89E).
  - S 89E needs amendment to align with the PEDPA.
- Mining-specific:
  - Under the Mining Act the Commissioner may require an environmental performance bond (s 112).
  - The ITA contains no provision relating to the tax treatment of mine closure and rehabilitation costs; such costs are recognized for tax purposes as incurred when there may be no income to offset them.

### Social infrastructure expenditure
- Context:
  - Holders of mining or petroleum rights may incur “social infrastructure expenditure” (school, hospital, community facilities) either under contractual requirement or voluntarily (corporate social responsibility).
- Current treatment:
  - No specific ITA rules; deductibility depends on general principles: expense must have sufficient connection to deriving business income.
  - Distinction: expenditure incurred in deriving business income (deductible) versus application of business income after derivation (non-deductible, e.g., charitable donation).
  - Determination is case-by-case on facts and circumstances.
- Recommendation:
  - ITA could distinguish compulsory social infrastructure expenditure (deductible and aligned with exploration/development treatment) from voluntary expenditure (treated under general principles).
  - If compulsory expenditure incurred during exploration, deduct as exploration; if during development, deduct as development.

### Thin capitalization
- Current rule:
  - ITA includes a thin capitalization rule (s 89) to protect the income tax base from excessive interest deductions.
  - Where a foreign-controlled resident company (not a financial institution) has a foreign debt-to-foreign equity ratio in excess of 1 to 1, a deduction is disallowed for interest on the part of debt exceeding the 1 to 1 ratio.
  - Prior to 2014 the allowable ratio was 2 to 1.
- Observations and recommendation:
  - Some countries limit excessive debt only to related-party debt; this has enforcement difficulties with back-to-back loans or parent guarantees.
  - Recommendation: extend the limit on excessive debt to all loans and increase the allowable debt-to-equity ratio to 1.5 to 1.

### Ring fencing (sector application)
- Current practice:
  - Uganda rings fences income from petroleum operations from other income contract by contract.
  - For variable income tax, Uganda ring fences income from mining operations (which could be from two or more projects operated by the same company).
  - Uganda does not currently ring fence different mining projects carried out by a single company.
- Consideration:
  - Consider ring fencing future mining projects, though not a high priority.
  - Any ring-fence should be consistent with classification under the MA and by reference to license areas granted.

### Transfer of interest (direct transfers and farm-outs)
- Modes of transfer:
  - Direct transfer: transfer of the whole or part of the right itself.
  - Indirect transfer: transfer of the owner’s interest in the entity holding the right.
- Direct transfers — statutory rules and issues:
  - S 89G contains rules for transfer by a contractor of an interest in a petroleum agreement, but the rules are "confusing in their operation."
  - On transfer, the holder disposes of business assets (tangible and intangible). The gain or loss from disposal of each asset must be determined, including depreciation or amortization recapture.
  - The transfer agreement allocates consideration across assets; significant consideration likely allocated to the mining or petroleum right.
  - A mining or petroleum right is a business asset (s 2).
  - Tax treatment of gain depends on:
    - Tax rules for business income (including gains on disposal of business assets).
    - Depreciation recapture rules.
    - Any applicable tax treaty.
  - Tangible assets: depreciated within a pool under s 27; consideration reduces pool balance; consideration exceeding written down value is included in business income.
  - Intangible assets: gain on disposal included in business income under s 18(1)(a); cost reduced by deductions allowed (notably amortization under s 31).
  - Chargeable income for the transferor year = total business income reduced by total allowable deductions, including s 38 deduction for losses carryforward. Deducted exploration and development losses carried forward reduce gain on disposal.
- Treatment of undeducted intangible capital expenditure:
  - Issue for items like drilling expenditure that have not been fully deducted at transfer (deductibility may not start until commercial production).
  - Proposal: treat undeducted intangible expenditure as giving rise to a notional intangible (and business) asset disposed of at transfer; cost equals amount of expenditure.
  - Normal disposal rules then apply, potentially creating a loss equal to the undeducted cost treated as a deduction under s 22(1)(b).
- Farm-outs:
  - Farm-out agreement: holder of a right ("farmor") may transfer a percentage interest to a "farmee" in exchange for cash and/or the farmee assuming some or all of the farmor’s future work commitments.
  - Transfer timing:
    - Immediate transfer farm-out agreement: transfer on signing.
    - Deferred transfer farm-out agreement: transfer occurs upon farmee fulfilling work commitments. 

*cr17367 - 139.      While the 2010 amendments included the detailed rules on deductible expenditures*

### 168.      A farm-out agreement may be characterized as a transfer of interest in return for

### 168.      A farm-out agreement may be characterized as a transfer of interest in return for

### Farm-out agreements: characterization and tax treatment
- A farm-out agreement may be characterized as a transfer of interest in return for the farmee meeting the costs of the farmor’s future work commitments.
- A farm-out may also oblige the farmee to pay a cash amount, usually on signing; the tax treatment of that cash amount depends on its characterization:
  - If characterised as a pro-rata reimbursement by the farmee of the past costs incurred by the farmor that relate to the interest transferred, and those costs have been deducted by the farmor (such as exploration expenditure), the cash reimbursement:
    - May be properly characterised as reimbursed tax deductions and included in business income under s 62 of the ITA.
    - Will reduce the loss carryforward comprising the deducted expenditure.
  - If the past costs have not been deducted (for example, development expenditure incurred before the commencement of commercial production), the reimbursement will reduce the deductible amount of the expenditure for the farmor.
  - The farmee should be allowed a deduction under the normal rules for deduction of mining or petroleum expenditure to the extent the cash amount is a reimbursement of the farmor’s past costs.
  - If the cash amount paid by the farmee exceeds the amount reasonably characterised as a reimbursement of the farmor’s past costs, the excess should be included in income as a gain on the transfer of the interest in the mining or petroleum right.
- Treatment of future work commitments:
  - Future work commitments undertaken by the farmee (relating to the interest retained by the farmor) may be characterised either as in-kind income of the farmor, or as in-kind consideration for the transfer of the interest to the farmee.
  - The value of work commitments may be excluded from income and not treated as consideration for the transfer of the interest (approach taken in Kenya). Under that approach only the cash amount is taxed as described above.
  - The deduction for costs of the farmor carried by the farmee under a farm-out agreement should be deductible only to the farmee.
- Recommendation implicit in text: include rules dealing with farm-outs.

### Indirect transfers of mining or petroleum interests — principles and enforcement
- Economic basis:
  - Shares or other equity interests derive value from the assets held by the entity; if the principal asset is a mining or petroleum right, the value of the shares equates to the value of the right.
  - Gains on disposal of shares in a company holding a mining or petroleum right should equate to the gain the company would derive on disposal of the right.
- Tax policy and international norms:
  - Taxation of indirect transfers is important to protect the integrity of Uganda’s taxation of direct transfers and is consistent with Article 13(4) of the OECD Model.
- Current law and gaps:
  - Gains on indirect transfers are taxable under the ITA: shares are business assets as defined in s 2; gains on disposal of business assets are included in business income under s 18(1)(a) of the ITA.
  - A non-resident’s gain is included in business income only if it has a Ugandan source.
  - S 79(g) provides the gain on disposal of a share in a company the property of which consists, directly or indirectly, principally of immovable property in Uganda is Ugandan-source income.
  - Risk: the source rule could be avoided through interposition of a unit trust or limited partnership in an offshore chain and disposing of units or interests.
  - Proposal: s 79(g) should be revised to apply also to the disposal of a unit in a unit trust and an interest in a partnership.
  - Important that the meaning of “immovable property” includes mining and petroleum rights.
- Treaties and treaty shopping:
  - Presently only treaties with China and India preserve Uganda’s taxation of gains on indirect transfers, and then only in relation to disposal of shares in companies.
  - This creates potential for treaty shopping if the non-resident company making the gain is resident in a treaty country that does not provide for taxation of gains on indirect transfers.
  - S 88(5) of the ITA provides some protection, but all future treaties should preserve Uganda’s taxing rights over gains on indirect transfers.
- Administrative enforcement (two aspects):
  - Discovery: s 87 of the Petroleum (EDP) Act requires the Minister to approve a change in control of a license holder. There is no equivalent in the Mining Act as s 7 applies only to transfer of mineral rights.
    - Proposal: extend s 7 to apply to change in control of the holder of the mineral right and make applicable under s 87 of the PEDPA.
    - Provide that the relevant Ministry has an obligation to advise URA of a change in control of the holder of the mining or petroleum right so URA can pursue collection; alternatively impose the reporting obligation on the holder under the ITA.
  - Collection: treat the holder of the mining or petroleum right as agent of the non-resident person liable for the tax. If the non-resident does not pay, the contractor is treated as personally liable, allowing URA to collect unpaid tax from the holder using normal debt recovery rules under the Tax Procedures Code.

### Recommendations (from resource taxation and indirect transfers sections)
- Adopt common rules for mining and petroleum development expenditure (including depreciable assets).
- Allow a tax deduction for deposits into an approved escrow account for future decommissioning, mine closure and rehabilitation expenses.
- Provide for the deductibility of compulsory social infrastructure expenditure, and align the deductibility with exploration and development expenditure.
- Extend the thin capitalization rule to cover all debt and increase the allowable debt-to-equity ratio to 1.5 to 1.
- Consider ring fencing future mining project license area by license area with exceptions only for failed exploration on relinquished areas elsewhere, and for technically warranted joint development or adjacent mines.
- Ensure that undeducted capital expenditure is recognized on a transfer of interest.
- Include rules dealing with farm-outs.
- Provide administrative rules to facilitate the collection of tax in relation to indirect transfers.

### International income tax — Taxation of subcontractors
- Sector context:
  - The resources sector involves a high level of subcontractors, particularly non-resident subcontractors.
  - Petroleum local content rules in s 125 of the Petroleum (EDP) Act may significantly limit use of non-resident subcontractors; s 113 of the Mining Act is not as strict.
- Benchmark for taxing non-resident subcontractors:
  - Taxation should be limited to Ugandan-source technical fees.
  - Basis of taxation should depend on whether the subcontractor has a branch in Uganda:
    - If the non-resident derives technical fees through a branch in Uganda: tax on a net basis (chargeable income) at the normal corporate rate on an ordinary assessment basis.
    - If the non-resident does not have a branch in Uganda: Ugandan-source technical fees should be subject to final withholding tax on the gross amount of the fee.
  - Tax treaties may limit or exclude Uganda’s taxation of technical fees derived by a non-resident subcontractor.
- Current statutory framework issues:
  - Ss 85, 119, and 121 of the ITA apply to technical fees derived by non-resident subcontractors but do not clearly delineate when technical fees are taxed on a gross or net basis.
  - Rules for determining when a technical fee is Ugandan-source need modernization.
- Source of services (s 79):
  - Four bases under s 79 for services income to be Ugandan-source:
    - Services rendered in Uganda (s 79(c)); s 79 provides for apportionment for partly performed services.
    - Services rendered under a contract with the Government of Uganda (s 79(d)).
    - Services Uganda is permitted to tax under a tax treaty (s 79(r)).
    - Services attributable occurring in Uganda, including activity conducted through a Ugandan branch (s 79(s)).
  - Recommendation: align source rule for services income with place of utilization, similar to royalties—services income should have a source in Uganda when paid by:
    - (i) a Ugandan resident (other than as an expenditure of a business carried on by the resident outside Uganda through a branch); or
    - (ii) a non-resident as an expenditure of a Ugandan branch.
  - This alignment should apply regardless of whether the service fee is paid directly to the non-resident service provider, or through a recharge arrangement with a related non-resident company.
- Branch taxation and definition of “branch”:
  - Services attributable to a Ugandan branch of a non-resident contractor should be taxed on an ordinary assessment basis rather than through final withholding.
  - Current practice: URA applies non-final withholding under s 119 to technical fees derived by Ugandan branches of non-residents; this practice should be formalized by excluding operation of s 85 when the fee is attributable to activities conducted by a non-resident through a Ugandan branch (align s 85 with s 83 (see s 83(6))).
  - The definition of “branch” in s 78 should be reviewed and modernized; include a services branch rule based on Article 5(3)(b) of the UN Model:
    - Furnishing of services in Uganda by a person through employees or other personnel treated as a branch only if rendering of services continues for the same or a connected project within Uganda for a period or periods aggregating more than 183 days in any 12-month period commencing or ending in the year of income.
    - This aligns “branch” with “permanent establishment” under Uganda’s tax treaties with China, Mauritius and Norway.
- Withholding rate and economic effects:
  - Rate under s 85 of the ITA is 15 percent of the gross amount of the fee.
    - Comment: assuming a 50 percent profit margin, 15 percent on gross roughly equates to 30 percent on net; but where subcontractor expenses are significant, 15 percent on gross may equate to a much higher rate on net income.
    - Note: the rate limit under the technical fees article of Uganda’s tax treaties is 10 percent (other than the UK treaty where the rate limit is 15 percent).
  - Withholding can increase project costs because subcontractors may require contracts net-of-tax and gross-up prices.
  - Recommendation: review the 15 percent rate; consider reducing to 10 percent to align with the tax treaty rate.

### Tax treaties — policy guidance
- Tax treaties can significantly reduce government take from resource sector.
- Uganda has a model tax treaty intended for future negotiations; the model should be carefully reviewed.
- For resource operations, ensure future treaties:
  - Include a services permanent establishment rule.
  - Preserve Uganda’s taxing rights in relation to lease payments, technical fees, and gains on indirect transfers.
- Recommendation list (reiterated):
  - Modernize the source rules for technical fees paid to non-residents.
  - Tax subcontractors on a net basis when the fee is attributable to a branch in Uganda.
  - Reduce the withholding tax rate on technical fees to 10%.
  - Ensure Uganda’s tax treaties include a services permanent establishment rule, and preserve Uganda’s taxing rights in relation to lease payments, technical fees, and gains on indirect transfers.

### VAT treatment of the petroleum and mining chain — design issues, refunds, and registration
- VAT design and resource sector impact:
  - VAT is collected on imports and at each stage of production/distribution; businesses engaged in supply of taxable goods and services must register and charge VAT.
  - Liability is remittance of net VAT: output tax less input tax.
  - Uganda exempts imports from VAT (18 percent standard rate) if goods are exempt under the Fifth Schedule of the EAC Customs Management Act.
  - The design of Uganda’s VAT includes several deficiencies that burden investments in exploration and development and downstream facilities; these should be addressed as an integrated package.
- VAT refunds:
  - Common complaint: delay in refund payments due to burdensome administrative requirements and URA’s lack of financial resources to make payments—payments restricted by a budgeted amount for refunds.
  - Recommendation (from 2011 FAD tax policy mission): end budgeting for VAT refunds as a spending item and move to VAT accounting on a net basis.
- VAT registration for resource companies:
  - Resource companies cannot register for VAT and claim input tax credits during exploration and development phases since they are not yet supplying goods or services.
  - Under Uganda law a company supplying goods or services that is not required to register for the VAT can voluntarily register and claim input tax credits (s 7(4)), but resource companies are not supplying taxable supplies during exploration/development.
  - Prior to 2012, VAT regulations (s 6) allowed voluntary registration as an investment trader; the regime was repealed due to concerns about erroneous refunds if the taxpayer never made taxable supplies and concerns about abuse and audit resource needs.
  - Policy observation: VAT is a tax on final consumption; if an investor fails to launch and never makes supplies, no net VAT should arise—failed investment is not final consumption.

*Source: cr17367 - 168.      A farm-out agreement may be characterized as a transfer of interest in return for*

### 189.      In 2011, the FAD tax policy mission recommended that the government should

### cr17367 - 189.      In 2011, the FAD tax policy mission recommended that the government should

### VAT registration for resource companies and refunds
- Finding: In 2011, the FAD tax policy mission recommended repeal of the refund scheme for registered investment traders and that refunds of input tax credits be provided prior to the commencement of taxable supplies. The first part was adopted but not the second. Under current law, a resource company cannot register during exploration and development phases and cannot claim input tax credits for taxable supplies made prior to registration.
- Effect: Non-creditable VAT payments add to project costs; for petroleum projects some VAT can be recovered through cost oil once production commences, but the company is not fully refunded because higher cost oil reduces profit oil and thus the company’s profit oil.
- Recommended preferred reform:
  - Allow resource companies to register voluntarily for VAT during exploration and development phases and during construction phase of downstream facilities (refineries and pipelines).
  - Strengthen the VAT refund system to pay refund claims that have been duly vetted.
- Alternative approaches:
  - Allow resource companies to carryforward the input tax credit (with interest) to be offset against output tax once production commences (eliminates immediate budget effect).
  - For petroleum companies, carryforward input tax credit (with interest) and make the accumulated amount the first claim on the government’s share of profit oil when production is split (would likely require amendment to PSAs).

### VAT on imports and subcontractors
- Current law: Goods exempt from customs duty under the Fifth Schedule of the EAC Customs Management Act are exempt from VAT (s 20). Customs exemptions exist for licensed petroleum and mining companies; petroleum exemption covers machinery and inputs for direct and exclusive use in exploration and development; mining exemption only covers machinery and spare parts. Other inputs generally subject to import duty of 10 percent (intermediate goods) or 25 percent (finished goods).
- Problem: Subcontractors import a large share of inputs and these imports are not exempt under Customs Management Act → subject to VAT in Uganda.
- Recommended amendments to Customs Management Act:
  - Extend import exemption for resource companies to apply to subcontractors if goods are for direct and exclusive use in a resource project.
  - Broaden mining exemption to parallel petroleum exemption (cover machinery and inputs).
- Interim/legal alternative: Amend VAT Act to exempt imports by a subcontractor from VAT where the importation would be exempt under the Fifth Schedule and the subcontractor is a licensed petroleum or mining company.
- Safeguards suggested to limit abuse:
  - Require the petroleum or mining company holding the license to certify goods will be used for the project and that goods have arrived on site.
  - Use an independent surveillance and tracking company to verify chain of custody; costs borne by license holders but cost recoverable.

### Treatment of domestic suppliers; remission scheme as interim measure
- Finding: Local companies must charge VAT on supplies to resource companies, but resource companies cannot recover input VAT → local suppliers disadvantaged relative to importers (many imports exempt).
- Preferred solution: Allow resource companies to register and pay timely refunds of excess VAT credits; move VAT accounting to a net basis (end budgeting for VAT refunds as a spending item).
- Government view: Practical constraints on paying refunds in the short term → second best interim options needed.
- Zero-rating local supplies to resource companies: Considered but not recommended (could shift refund problems and create administrative problems for URA).
- Accounts-based remission scheme (recommended interim measure):
  - Mechanism example:
    - If supplier charges $10 output tax and has $4 input tax, supplier normally remits $6 to URA. Under remission scheme, supplier has $10 deemed output tax, claims $4 input tax, owes $6; Government remits the $6 on behalf of the supplier.
  - Key characteristics:
    - Supply remains taxable at the standard VAT rate but VAT is paid by Government through deeming rule.
    - Limit remission to first tier of suppliers to resource companies.
    - Suppliers in excess input tax credit situations must have procedures for payment of refunds; these refunds likely relatively small compared to refunds to resource companies but important to signal support for local suppliers.
  - Fiscal implication: Use of output tax receipts from non-resource customers by suppliers to cover input tax related to resource company sales will reduce net VAT remittances to URA — viewed as a small necessary increase in overall VAT refund budget.
- Transition: Remission scheme is a second best interim solution until a properly functioning refund system for resource companies is implemented.

### Reverse charge rule and imported services
- Explanation: Reverse charge requires purchaser to account for VAT on services supplied by non-residents; purchaser self-assesses output tax and may claim corresponding input tax credit if making taxable supplies — net effect is typically no VAT payable.
- Preferred practice: Account for reverse charge and input tax credit in the same tax period; VAT-registered companies would report the reverse charge in a separate schedule on the monthly VAT return.
- Policy change and effect in Uganda: In 2012 Uganda repealed the credit for VAT paid on imported services (s 5(c)); importer of a service is treated as an end-user and VAT chain is broken — investment is taxed.
- Effect on resource sector: Imposes effectively an 18 percent import duty on imported services, increasing cost of investments; though recoverable as part of cost oil and deductible under income tax, it still raises investment cost.
- Urgent recommendation: Restore the input tax credit for the reverse charge before the request for proposals for the first petroleum licensing round issued on July 20, 2015.

### VAT on petroleum products
- Current policy: Uganda levies excises on gasoline, diesel, and illuminating kerosene while exempting these products from VAT (second schedule 1(o)). Other petroleum products such as lubricants are subject to VAT.
- Conceptual framing: The excise on VAT-exempt products can be viewed as comprising (i) the VAT at the 18 percent rate and (ii) a true excise equal to tax in excess of the VAT that would otherwise apply.
- Workability: Exempting petroleum products from VAT is workable while all petroleum products are imported and excise is collected by customs. Not workable when domestic crude production and local refining begin because crude oil producers will charge VAT on production sold to refinery; if refined products remain VAT-exempt, refinery cannot claim input tax credit.
- Table 9 (excise and embedded VAT on petroleum products) — figures preserved exactly:
  - Gasoline
    - Retail Price (UGX per liter): 3,600
    - Excise (UGX per liter): 950
    - Embedded VAT (18 percent)1/: 549
    - True Excise (UGX per liter): 401
  - Diesel
    - Retail Price (UGX per liter): 2,800
    - Excise (UGX per liter): 630
    - Embedded VAT (18 percent)1/: 427
    - True Excise (UGX per liter): 203
  - Illuminating kerosene
    - Retail Price (UGX per liter): 200
    - (no further table data provided)
  - Note 1/: 15.25 percent on a tax inclusive basis
- Preferred reform:
  - Repeal the VAT exemption for petroleum products and adjust (reduce) excise rates.
  - Example from region: Kenya extended VAT to petroleum products with a three-year transitional arrangement; petroleum products subject to VAT from September 1, 2016.
  - Rationale: Ensures VAT chain is not broken; businesses that use petroleum products to produce taxable supplies can claim input tax credit.
  - Fiscal impacts:
    - With downward adjustment of excise rates, reform could be price neutral but may lead to a small decrease in government revenue because explicit VAT embodied in excise is not currently allowed as an input credit.
    - Reform could be revenue enhancing if excise reduction is smaller than required for revenue neutrality.
    - Given likely rising oil prices in near term, shifting tax burden from specific levy to combination of specific levy and ad valorem levy (VAT) would increase revenue in the near term.
- Alternative approach:
  - Impose VAT on refined petroleum products at a single stage (imported or sold by refinery) using the monthly average retail price determined by Uganda Bureau of Statistics and a tax-inclusive rate of 15.25 percent.
  - Under this approach the refinery could claim input tax credits; products would remain VAT-exempt at distribution and retail stages.
  - Rationale for single-stage approach: Avoid VAT revenue leakage at retail stage where many sellers are not required to register; used for cigarettes and alcoholic beverages.
  - Caveat: Adds a special VAT regime and could cause initial confusion.

### Consolidated recommendations (VAT and petroleum)
- Prior to release of the request for proposals for the first petroleum licensing round, adopt an integrated package of VAT reforms:
  - Allow companies to register voluntarily for VAT during the exploration and development phases of a resource project and allow refineries and pipelines to register during the construction phase of midstream facilities;
  - Exempt imports by a subcontractor from VAT if the imports are for direct and exclusive use in a resource project;
  - Adopt a limited remission scheme for first tier domestic suppliers to a resource project, with assured refunds of excess credits;
  - Allow an input credit for the reverse charge;
  - Repeal the VAT exemption for petroleum products and reduce the excises on these products.

### Fiscal stability clauses in resource contracts
- Context: Fiscal stability clauses are widespread in petroleum and mining contracts, justified by (1) large and sunk initial investments, (2) long recovery periods, and (3) lack of host country credibility to refrain from changing fiscal rules after investments are sunk.
- Countervailing factors reducing need for stability clauses: history of sound fiscal management, statutory and effective corporate tax rates in line with international rates, low tariff rates and absence of taxes that distort investment, non-discrimination, low corruption, transparent tax policy, and efficient tax administration.
- Current legal framework: No provision in PEDPA or the Mining Act or other legislation for government to give assurances of fiscal stability. Stability assurances have been given in PSAs and a recent mineral agreement, with language to preserve net present value for the mining company (including possible cash payments or government deemed payments of additional tax).
- Proposed legal change:
  - Amend the Mining Act to make fiscal stability assurances permissible under fixed terms.
  - Assurances should be time limited to five years from start of commercial production and cover only income and withholding tax rates, royalty rates, and cost recovery rules for capital expenditure.
  - General tax law changes that apply to businesses generally and do not discriminate against resource sectors (e.g., thin capitalization rule changes) would still apply.
- Recommendations:
  - Amend the Mining Act to make a fiscal stability assurance available if conditions specified in the Act are met.
  - Ensure assurances are time limited and cover only income and withholding tax rates, royalty rates, and cost recovery rules for capital expenditure.

*IMF staff report text.*

### 211.      Stamp duty is charged on a wide variety of financial, trading, and other

### 211.      Stamp duty is charged on a wide variety of financial, trading, and other transactions

### Principal stamp duty instruments affecting resource companies
- Most of Uganda’s stamp duties are specific levies (e.g., UGX 5,000 per document).
- Principal ad valorem duties affecting resource companies:
  - 0.5 percent duty on new share capital
  - 0.5 percent duty on debentures
  - 1 percent duty on the total value of a lease or a hire/purchase agreement
  - 1 percent of the total value of a transfer of shares (0.5 percent if the company is listed on a stock exchange)

### Advantages of stamp duties
- Attach to documents (which have no legal force unless properly stamped).
- Attach to the gross revenue of transactions (not requiring any sophisticated calculations to determine net "income").
- Seen as relatively secure sources of revenue, with relatively low costs of collection for the revenue authorities.

### Drawbacks of stamp duties
- Must be paid each time a dutiable document is handled or payment received, creating a cascade effect:
  - If a single transaction requires different documents to be prepared at successive stages.
  - If an asset is transferred at short intervals.
  - If the transaction requires offsetting payments to be made.

### Recommendation
- Consider eliminating ad valorem stamp duties that apply to financing transactions and increased equity.

### Appendix 1 and Appendix 2 — International comparators
- Appendix 1 contains Table A.1 and Table A.2: Fiscal regimes of international comparators for upstream petroleum and for mining, with detailed entries by country on regime type, royalty rates, cost recovery limits, state share, corporate income tax, depreciation rules, loss carry forward, supplementary profit tax, VAT, duties, dividend withholding tax, interest withholding tax, and state participation. (Tables include country-level entries such as Australia, Chad, Colombia, Democratic Republic of the Congo, Kenya, Mozambique, Sudan, Tanzania, and numerous mining comparators including Australia - Western Australia, Brazil, China, Guinea, India, Liberia, Mauritania, Russia, South Africa, Ukraine, etc., with the exact rates and rules as presented in the source.)
- Appendix 2 contains Table A.3: Royalties and Minimum Effective Royalties for Crude Oil in Selected Countries, listing for many countries (including Afghanistan, Algeria, Angola, Argentina, Azerbaijan, Bahrain, Bangladesh, Bolivia, Brazil, Brunei, Bulgaria, Burundi, Cambodia, Cameroon, Canada, Chad, China, Colombia, Congo DR, Congo Republic, Cote d'Ivoire, Ecuador, Egypt, Equatorial Guinea, Ethiopia, Gabon, Ghana, Guinea Bissau, Hungary, Iceland, India, Indonesia, Iraq, Israel, Italy, Japan, Kazakhstan, Kenya, Korea South, Liberia, Libya, Malawi, Malaysia, Mozambique, Myanmar, Namibia, Netherlands, New Zealand, Niger, Nigeria, Oman, Pakistan, Papua New Guinea, Peru, Philippines, Poland, Qatar, Romania, Russia, Sao Tome and Principe, Senegal, Sierra Leone, South Africa, South Sudan, Sudan, Syria, Tanzania, Thailand, Timor-Leste, Trinidad and Tobago, Tunisia, Turkmenistan, Uganda, Ukraine, United States, Uzbekistan, Venezuela, Vietnam, Yemen, Zambia) the following fields where provided: Oil royalty rate ; PSC type, Cost recovery limit, State share, PSC-imposed implicit royalty rate, Minimum effective royalty, Maximum effective royalty rate, Region, and Comments. (Appendix tables preserve the exact percentage figures, ranges, and notes as in the source text.)

### Appendix 3 — FAD Tax Policy and Revenue Administration Reports
- Lists IMF Technical Assistance Reports and other reports referenced in the chapter, including works by Baer, Katherine; Daniel, Philip; Harrison, Graham; Hutton, Eric; Keene, Vinette; Kloeden, David; Perry, Victoria; Sunley, Emil M.; and others, with the exact titles and years as presented in the source.

*Source: cr17367 - 211. Stamp duty is charged on a wide variety of financial, trading, and other transactions (IMF).*

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_Source: https://www.imf.org/-/media/files/publications/cr/2017/cr17367.pdf_